BKH | 2013 BKH Black Hills Corporation | Annual Report | Proxy Statement | Form 10K | Form Statement | Proxy Report | Annual Growth 2013 Black Hills Corporation
Annual Report Proxy Statement Form 10K
www.blackhillscorp.com
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Use bounding box to hide marks and text once placed. MONTANA SOUTH DAKOTA Investor Information 39 utility customers 2 communities served 66,389 utility customers 2013 Annual Report 558 employees 23 communities served 155 megawatts of operated WYOMING power generation capacity Common Stock 2014 Annual Meeting 78,639 utility customers IOWA 291 employees Transfer Agent, Registrar & Dividend Disbursing Agent The Annual Meeting of Shareholders will be held at The Dahl 7 communities served 153,458 utility customers Wells Fargo Shareowner Services Arts Center, 713 Seventh Street, Rapid City, South Dakota, 301 operated oil & gas wells 183 employees P.O. Box 64854 at 9:30 a.m. local time on April 29, 2014. Prior to the meeting, 29 bcfe reserves 132 communities served St. Paul, Minnesota 55164-0854 formal notice, proxy statement and proxy will be mailed 213 million tons of 800-468-9716 to shareholders. coal reserves www.wellsfargo.com/shareownerservices 520 megawatts of operated NEBRASKA Market for Equity Securities power generation capacity Senior Unsecured Notes – Black Hills Corporation The Company’s Common Stock ($1 par value) is traded 198,504 utility customers Trustee & Paying Agent on the New York Stock Exchange (NYSE). Quotations for 435 employees Wells Fargo Bank, N.A. the Common Stock are reported under the symbol BKH. COLORADO 106 communities served 750 N. St. Paul Place, Suite 1750 The continued interest and support of equity owners are Dallas, Texas 75201 appreciated. The Company has declared Common Stock 168,351 utility customers dividends payable in each year since its incorporation in 313 employees First Mortgage Bonds – Black Hills Power, Inc. 1941. Regular quarterly dividends when declared are normally 52 communities served KANSAS The Bank of New York Mellon payable on March 1, June 1, September 1 and December 1. 69 operated oil & gas wells 111,683 utility customers 101 Barclay Street, 8W 25 bcfe reserves 146 employees New York, New York 10286 Internet Account Access 425 megawatts of operated 62 communities served power generation capacity Registered shareholders can access their accounts First Mortgage Bonds – Cheyenne Light, Fuel & Power electronically at www.shareowneronline.com. Shareowner Trustee & Paying Agent Online allows shareholders to view their account balance, Wells Fargo Bank, N.A. dividend information, reinvestment details and much more. NEW MEXICO 750 N. St. Paul Place, Suite 1750 The transfer agent maintains stockholder account access. Dallas, Texas 75201 14 employees Direct Deposit of Dividends 135 operated oil & gas wells We encourage you to consider the direct deposit of your 24 bcfe reserves Pollution Control Refunding Revenue Bonds – Black Hills Power, Inc. dividends. With direct deposit, your quarterly dividend Trustee & Paying Agent payment can be automatically transferred on the dividend Wells Fargo Bank, N.A. payment date to the bank, savings and loan, or credit union 625 Marquette Ave., 11th floor of your choice. Direct deposit assures payments are credited Minneapolis, Minnesota 55479 to shareholders’ accounts without delay. A form is attached to Electric Utilities your dividend check where you can request information about Environmental Improvement Revenue Bonds this method of payment. Questions regarding direct deposit Natural Gas Utilities – Black Hills Power, Inc. should be directed to Wells Fargo Shareowner Services. Trustee & Paying Agent Power Generation The Bank of New York Mellon Dividend Reinvestment and Direct Stock Purchase Plan 1775 Sherman Street, Suite 2775 A Dividend Reinvestment and Direct Stock Purchase Plan Coal Mine Denver, Colorado 80203 provides interested investors the opportunity to purchase shares of the Company’s Common Stock and to reinvest Oil and Gas Industrial Development Revenue Bonds all or a percentage of their dividends. For complete details, 43 Consecutive Years of Dividend Increases – Cheyenne Light, Fuel & Power including enrollment, contact the transfer agent, Wells Fargo Corporate Office Trustee & Paying Agent Shareowner Services. Plan information is also available at US Bank National Association www.wellsfargo.com/shareownerservices. Company Headquarters 950 17th Street, Suite 1200 $1.52 $1.48 $1.46 $1.44 $1.42 Denver, Colorado 80202 Website Access to Reports $1.40 $1.37
$1.28 The reports we file with the SEC are available free of charge Corporate Offices at our website www.blackhillscorp.com as soon as reasonably $1.08 Black Hills Corporation practicable after they are filed. In addition, the charters of our $0.89 P.O. Box 1400 Audit, Governance and Compensation Committees are located $0.73 625 Ninth Street on our web site along with our Code of Business Conduct,
$0.21 Rapid City, South Dakota 57701 Code of Ethics for our Chief Executive Officer and Senior $0.13 $0.11 $0.43 605-721-1700 Finance Officer, Corporate Governance Guidelines of our 1970 1975 1980 1985 1990 1995 2000 2005 2007 2008 2009 2010 2011 2012 2013 www.blackhillscorp.com Board of Directors and Policy for Independent Directors.
Some of the sections in this annual report contain forward-looking statements. For a discussion about factors that could affect operating results, please see the Risk Factors beginning on page 51 of the Form 10-K. Cheyenne Prairie Generating Station construction underway. Align mark to the right with right edge of document.
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You might have As you can see from our 2013 results, expenses. The compound annual our strategy is definitely working. growth rate of adjusted earnings per heard us say more share from 2009 through 2013 was Last year, we achieved our third best 15 percent.* We achieved solid than once that our annual stock price performance financial results for shareholders — company has the since we were listed on the New all while maintaining operational York Stock Exchange in 1980. Our excellence and implementing most clearly defined stock price climbed higher every continuous improvement projects growth strategy in quarter, finishing the year up 44.5 that held down customer costs. percent. We also posted our highest our history. closing price in more than 10 years. In December, we increased our 2014 What’s more, our stock has recorded adjusted earnings guidance range to an 18.5 percent compound annual $2.50 to $2.70 per share, based on the growth rate since 2009. projected benefits from recent
44.5%
{ Year-End Stock Price & Growth BKH $52.51 12.7% 11.9% 8.2% + 44.5% -1.2% in 2013 $36.34
PEER GROUP $33.58 $30.00 + 22.1% $26.63 2009 2010 2011 2012 2013 S&P UTILITY INDEX 8.8% Year end stock price + Annual change in stock price S&P 500 + 29.6% BKH outperformed its peer group financing activities, which we’ll and the utility indexes — becoming detail later in this letter. DJIA the best performing stock in the + 26.5% utility sector. It also outpaced the Our earnings growth and positive S&P 500 Index and the Dow Jones outlook gave us confidence to Industrial Average amidst a banner maintain our dividend increase year for both markets. These results record. We declared our 43rd year aren’t unique to 2013; we’ve reported of consecutive dividend increases, strong results for the past four years. with a quarterly dividend of $0.38 per share — an annual increase Our rising stock price reflected of $0.04 per share and a dividend our improving performance. Our rate of $1.52 per share in 2013. In adjusted earnings per share of $2.45 early 2014, we also announced our were up 17 percent compared to the 44th consecutive year of increasing previous year’s adjusted earnings of dividends, one of the longest records $2.09 per share.* EPS benefited from in the utility industry. investments in our utility businesses, favorable weather and lower interest
*A Non-GAAP measure, reconciled to GAAP in the Proxy Statement, Appendix A, page 46. BKH | 2013 Black Hills Corporation | 1 Align mark to the right with right edge of document.
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Building momentum A number of favorable factors strengthened our balance sheet and gave us momentum as we moved into 2014, including:
Invested We invested $1.2 billion on capital In fact, we invested more than projects during the past three years, 60 percent of that $1.2 billion on our 1.2 billion on with much of that investment spent utilities, and we plan to continue that capital projects on our regulated utility businesses. trend in the future.
We drilled and completed two We earned about 20,000 net acres of Continued to horizontal wells in the Mancos Shale additional Mancos leasehold from a prove up formation in the southern Piceance third party in exchange for drilling Basin. Both wells are producing, and and completing the wells. Mancos properties we’re excited about their results.
We took advantage of low interest for 10 years. We used the proceeds Completed our rates and completed our largest debt to retire higher cost debt and settle offering ever, closing a 4.25 percent, interest rate swaps. This financing largest $525 million senior notes offering helped position our balance sheet to debt offering that locked in favorable interest rates support and grow our businesses.
Saw our The top three credit rating agencies and raised our credit rating. One recognized our improved financial agency already upgraded our credit credit rating performance and business risk profile rating again in early 2014. upgraded
More to come As encouraging as these 2013 results are, we believe they’re just the beginning. To help all of our stakeholders better understand our strategy and goals, we’ve broken our strategic plan into four major objectives: Profitable Growth, Valued Service, Better Every Day and Great Workplace.
2 | Oil and gas operations in Colorado.
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Use bounding box to hide marks and text once placed. PROFITABLE During the next three years, In Wyoming, we filed rate requests for GROWTH we plan to invest another Cheyenne Light to increase electric and $1.2 billion on capital projects natural gas system revenues to recover Achieve consistent to grow our business. We’ll investments in infrastructure. In early growth that invest more than half of that 2014, Black Hills Power also filed similar creates value. in our utilities. cases to recover such investments in South Dakota and Wyoming. Those Last year, we started construction investments include the Cheyenne on the next major project that will Prairie Generating Station and drive future earnings growth. The associated operating expenses. Cheyenne Prairie Generating Station is a $222 million, 132 megawatt, In Colorado, the Public Utilities Total Shareholder Return natural-gas-fired power plant in Commission granted Black Hills Cheyenne, Wyo. It will serve growing Energy – Colorado Electric approval 49.1% electricity demand in Cheyenne to build a 40 megawatt, natural-gas- and replace older, coal-fired power fired turbine to replace the capacity plants that we’ve retired in Wyoming lost from the coal-fired W.N. Clark and South Dakota to comply with plant that we retired to comply with EPA regulations. The project is on the Colorado Clean Air Clean Jobs schedule and within budget, and we Act and to meet ever-increasing expect that it will begin serving Black EPA regulations. Hills Power and Cheyenne Light, Fuel & Power customers in the fourth Throughout our utility service 18.3% 17.4% quarter of 2014. territories, we grew our customer base and revenue through small municipal
13.2% Black Hills Power and Cheyenne gas system acquisitions — adding 900 Light received approval from their customers and $6 million in rate base 5.2% respective utility commissions to during the past year. We announced implement quarterly rate adjustments another small acquisition in January 2008 2009 2010 2011 2012 2013 to recover financing costs during 2014, which will add another 400 construction of the plant. This was the customers in Wyoming when the Includes dividends first time we were able to use these transaction closes later in the year. innovative financing riders. These We plan to make similar acquisitions riders will reduce customers’ costs as when they make business sense. Total Annualized Return well as the time it takes our utilities to recover construction financing costs. At Black Hills Exploration & Beginning Ending Annual Stock Stock Total Production, we plan to continue Period Price** Price** Return*** For Black Hills Power customers in activities to prove up the upside 1 Year $34.96 $52.14 49.1% South Dakota, the Public Utilities potential of our shale gas assets. We Commission approved an increase of plan to drill six additional horizontal 3 Year $26.63 $52.14 25.1% $8.8 million, or 6.4 percent, in annual wells in the Mancos Shale formation 10 Year $19.54 $52.14 10.3% electric revenue. This allowed us to in 2014. We’re also continuing our recover our investments in electric limited and disciplined exploration 20 Year $4.2 $52.14 13.4% infrastructure and higher operating activity, looking to balance our See note on page eight for more information. costs since our last increase in reserve portfolio with more crude oil. April 2010.
** Daily closing stock prices adjusted for dividends and splits *** Average annualized returns calculated for the listed period through 12/31/2013 BKH | 2013 Black Hills Corporation | 3 Align mark to the right with right edge of document.
Use bounding box to hide marks and text once placed. BETTER A good portion of our success we use to support our customers. EVERY DAY is due to our strategic focus To that end, we have several ongoing on operational excellence. projects that will improve our Continuously improve We want to lead our industry customers’ experiences. to achieve industry in everything we do. Leading leading results. our industry means we’re Our ability to build and operate earning solid returns for our power plants is already industry shareholders and managing leading. Since 1995, we’ve built expenses and improving service 17 power plants, totaling 1,765 for our customers. megawatts of capacity. Our electric utilities have some of the newest, Our commitment to operational most modern generation fleets in excellence extends to the technology our industry.
Average generation Cheyenne Light, Colorado Black Hills fleet age Fuel & Power Electric Power as of December 2013 6.0 7.4 28.1 years old years old years old
Technology 22 Mobile-Friendly Website 22 QR Code integration 22 Energy Use Profile 00 Customer Notification 22 eBill 00 Customer Dashboard 22 New Bill Format 00 Self-Directed Apps {18% eBILL ENROLLMENT
22 New Interactive 00 Customer profile Voice Response options 22 Company blog
{48% PAYMENTS RECEIVED ELECTRONICALLY
4 | Inside our Electric ReliabilityAlign mark toCenter the right in with rightSouth edge Dakota.of document. VALUED Use bounding box to hide marks and text once placed. SERVICE Our customers expect a high power. Thanks to the center, our level of service at a good hundreds of employees, and help value. To continue to meet from our sister and peer utilities, we Deliver reliable, highly their needs, we launched new were able to restore most customers’ valued products websites for all of our utilities service within a week. and services. as well as for the corporation. We also unveiled our new Electric Our J.D. Power and Associates Reliability Center, which allows customer service scores show that us to safely and reliably keep the our efforts are working. In 2013, power on for our more-than our natural gas customer score was 200,000 electric customers and 643 — an improvement of 13 points respond more efficiently when the over 2012 — which exceeded the unexpected occurs. Midwest and industry averages. Our electric customer score was 628 — an Our Electric Reliability Center improvement of 34 points over 2012. proved invaluable in October 2013, when the Black Hills of South Dakota endured one of the worst blizzards in the region’s history. Consequently, Black Hills Power suffered its worst outage in our 130-year history, with more than half of our BHP customers left without
22 AMI/AMR 22 Reliability Center 22 Remote connect/ 22 Top quartile reliability disconnect 00 Automation & Detection 22 Outage management }89% ESTIMATED MANUAL METER READS
22 Operations Order Capture 00 Mapping 00 Dispatching (FSO) 00 GPS Tracking 00 Work Management
{39.7% }94.2% REMOTE CONNECT/ TRUCK DEPLOYMENTS DISCONNECT
BKH | 2013 Black Hills Corporation | 5 Align mark to the right with right edge of document. GREAT Use bounding box to hide marks and text once placed. WORKPLACE Our tremendous success Our emphasis on safety is making would not be possible without a difference. Although even one our talented and dedicated incident is too many, we’ve seen Promote a workplace employees. We want each of our safety performance improve that inspires individual them to go home safely to their 63 percent since 2010. Last year, our growth and pride in families at the end of every work Total Case Incident Rate was 1.7, what we do. day. That’s why we’re focused on compared to the industry average of becoming the safest energy company 2.8. In fact, three of our businesses in the industry. have gone years without a lost-time accident — including Black Hills Exploration & Production at two and Total Case Incident Rate a half years and Power Generation at four years. Our Wyodak Mine received an award from the State of Wyoming Mine Inspector for three
4.6 years without a lost-time accident. 4.3 63% IMPROVEMENT Because of our emphasis on safety, 2.8 SINCE 2010 diversity, recognition, engagement and wellness, Achievers — an organization that honors the 2.1
1.7 country’s top employers — 1.6 recognized us as one of the 50 most engaged workplaces for the second 2009 2010 2011 2012 2013 consecutive year. Also, the Denver Post named Black Hills Exploration Industry average & Production one of the top workplaces in Colorado.
6 | Restoring service in the Black Hills during the Align blizzardmark to the Atlas.right with right edge of document.
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The future is calling It’s been said that, “history doesn’t repeat itself, but it rhymes.” So, if our past — with its consistent growth and steady earnings — is an indicator, then our future sounds promising. Thank you for being a part of our journey.
Black Hills employees at a drill site in the Powder River Basin.
BKH | 2013 Black Hills Corporation | 7 Comparison of 5 Year Cumulative Total Return Assumes Initial Investment of $100 December 2013
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Black Hills Corporation S&P 500 Index - Total Returns S&P Midcap Electric Utilities
Note: Annual total stock returns on page 3 were calculated from www.buyupside.com using their stock return calculator. Total stock return considers dividends paid and stock splits. Black Hills Corporation does not guarantee the accuracy of these calculations, does not suggest Black Hills Corporation stock will perform in the future comparable to the past, and does not provide this information as investment advice.
8 | PROXY STATEMENT
BLACK HILLS CORPORATION
Notice of 2014 Annual Meeting of Shareholders and Proxy Statement PROXY STATEMENT PROXY
(This page left mostly blank intentionally.) BLACK HILLS CORPORATION
625 Ninth Street Rapid City, South Dakota 57701
NOTICE OF ANNUAL MEETING OF SHAREHOLDERS PROXY STATEMENT April 29, 2014
March 20, 2014
Dear Shareholder:
You are invited to attend the annual meeting of shareholders of Black Hills Corporation to be held on Tuesday, April 29, 2014 at 9:30 a.m., local time, at the Dahl Arts Center, 713 Seventh Street, Rapid City, South Dakota. The purpose of our annual meeting is to consider and take action on the following:
1. Election of four directors in Class II: David R. Emery, Rebecca B. Roberts, Warren L. Robinson and John B. Vering.
2. Ratification of Deloitte & Touche LLP to serve as our independent registered public accounting firm for 2014.
3. Adoption of an advisory, non-binding resolution to approve our executive compensation.
4. Any other business that properly comes before the annual meeting.
The enclosed proxy statement discusses these important matters to be considered at this year’s meeting. Our common shareholders of record as of March 10, 2014 can vote at the annual meeting.
Your vote is very important. You may vote your shares by telephone, by the Internet or by returning the enclosed proxy. If you own shares of common stock other than the shares shown on the enclosed proxy, you will receive a proxy in a separate envelope for each such holding. Please vote each proxy received. To make sure that your vote is counted if voting by mail, you should allow enough time for the postal service to deliver your proxy before the meeting.
Sincerely,
ROXANN R. BASHAM Vice President – Governance and Corporate Secretary PROXY STATEMENT PROXY
(This page left mostly blank intentionally.) BLACK HILLS CORPORATION
625 Ninth Street Rapid City, South Dakota 57701
PROXY STATEMENT PROXY STATEMENT
A proxy in the accompanying form is solicited by the Board of Directors of Black Hills Corporation, a South Dakota corporation, to be voted at the annual meeting of our shareholders to be held Tuesday, April 29, 2014, and at any adjournment of the annual meeting.
The enclosed form of proxy, when executed and returned, will be voted as set forth in the proxy. Any shareholder signing a proxy has the power to revoke the proxy in writing, addressed to our secretary, or in person at the meeting at any time before the proxy is exercised.
We will bear all costs of the solicitation. In addition to solicitation by mail, our officers and employees may solicit proxies by telephone, fax, or in person. We have retained Georgeson Inc. to assist us in the solicitation of proxies at an anticipated cost of $7,500, plus out-of-pocket expenses. Also, we will, upon request, reimburse brokers or other persons holding stock in their names or in the names of their nominees for reasonable expenses in forwarding proxies and proxy materials to the beneficial owners of stock.
This proxy statement and the accompanying form of proxy are to be first mailed on or about March 20, 2014. Our 2013 annual report to shareholders is being mailed to shareholders with this proxy statement.
VOTING RIGHTS AND PRINCIPAL HOLDERS
Only our shareholders of record at the close of business on March 10, 2014 are entitled to vote at the meeting. Our outstanding voting stock as of the record date consisted of 44,630,910 shares of our common stock.
Each outstanding share of our common stock is entitled to one vote. Cumulative voting is permitted in the election of our Board of Directors. Each share is entitled to four votes, one each for the election of four directors, and the four votes may be cast for a single person or may be distributed among two, three or four persons. TABLE OF CONTENTS
Commonly Asked Questions and Answers About the Annual Meeting Process 1 Proposal 1 - Election of Directors 4 Corporate Governance 7 Meetings and Committees of the Board 10 Director Compensation 12 Security Ownership of Management and Principal Shareholders 14
PROXY STATEMENT PROXY Proposal 2 - Ratification of Appointment of Independent Registered Public Accounting Firm 16 Fees Paid to the Independent Registered Public Accounting Firm 16 Audit Committee Report 17 Executive Compensation 18 Compensation Discussion and Analysis 18 Compensation Committee Report 28 Summary Compensation Table 29 Grants of Plan Based Awards in 2013 31 Outstanding Equity Awards at Fiscal Year-End 2013 32 Option Exercises and Stock Vested During 2013 33 Pension Benefits for 2013 34 Nonqualified Deferred Compensation for 2013 37 Potential Payments Upon Termination or Change in Control 38 Proposal 3 - Advisory Vote on Our Executive Compensation 43 Transaction of Other Business 44 Shareholder Proposals for 2015 Annual Meeting 44 Shared Address Shareholders 44 Annual Report on Form 10-K 45 Notice Regarding Availability of Proxy Materials 45 Appendix A - Reconciliation of Non-GAAP Financial Measures 46 COMMONLY ASKED QUESTIONS AND ANSWERS ABOUT THE ANNUAL MEETING PROCESS
Who is soliciting my proxy?
The Board of Directors of Black Hills Corporation is soliciting your proxy. PROXY STATEMENT Where and when is the annual meeting?
The annual meeting is at 9:30 a.m., local time, April 29, 2014 at the Dahl Arts Center, 713 Seventh Street, Rapid City, South Dakota.
What am I voting on?
You are voting on:
• Election of four directors in Class II: David R. Emery, Rebecca B. Roberts, Warren L. Robinson and John B. Vering; • Ratification of Deloitte & Touche LLP as our independent registered public accounting firm for 2014; and • Adoption of an advisory, non-binding resolution to approve our executive compensation.
Who can vote?
Holders of our common stock as of the close of business on the record date, March 10, 2014, can vote at our annual meeting. Each share of our common stock has one vote for Items 2 and 3. Cumulative voting is permitted in the election of directors. Each share is entitled to four votes for the election of directors, one each for the election of four directors, and the four votes may be cast for a single person or may be distributed among two, three or four persons.
How do I vote?
There are three ways to vote by proxy:
• by calling the toll free telephone number on the enclosed proxy; • by using the Internet; or • by returning the enclosed proxy in the envelope provided.
You may be able to vote by telephone or the Internet if your shares are held in the name of a bank or broker. If this is the case, you will need to follow their instructions.
If we receive your signed proxy before the annual meeting, we will vote your shares as you direct. You can specify on your proxy whether your shares should be voted for all, some or none of the nominees for director. You can also specify whether you approve, disapprove or abstain from the other proposals.
If you do not mark any sections, your proxy card will be voted:
• in favor of the election of the directors named in Proposal 1; and • in favor of Proposals 2 and 3.
Who will count the vote?
Representatives of our transfer agent, Wells Fargo Bank, N.A., will count the votes and serve as judges of the election.
1 PROXY | 1 What constitutes a quorum?
Shareholders representing at least 50 percent of our common stock issued and outstanding as of the record date must be present at the annual meeting, either in person or by proxy, for there to be a quorum. Abstentions and broker non-votes are counted as present for establishing a quorum. A broker non-vote occurs when a broker or other nominee holding shares for a beneficial owner does not vote on a particular proposal because the broker or nominee does not have discretionary voting power and has not received instructions from the beneficial owner.
What vote is needed for these proposals to be adopted?
Item 1 – Election of Directors. The affirmative vote of a plurality of the votes cast at the meeting is required for the election of directors. This means that the four nominees with the largest number of votes “For” will be elected as directors. A properly executed proxy marked “Withhold authority” with respect to the election of one or more directors will not be voted with respect PROXY STATEMENT PROXY to the director or directors indicated, although it will be counted for purposes of determining whether a quorum is present.
We have adopted a "plurality plus" guideline for director elections. Pursuant to our Corporate Governance Guidelines, any nominee for director in an uncontested election who receives a greater number of votes "Withheld" from his or her election than votes "For" such election must promptly tender his or her resignation to the Chairman of the Board. The Governance Committee will consider that resignation and will recommend to the Board whether to accept the tendered resignation or reject it based on all relevant factors. The Board will publicly disclose by filing with the Security and Exchange Commission ("SEC") on Form 8-K its decision and, if applicable, its rationale within 90 days after receipt of the tendered resignation.
Item 2 – Ratification of Auditors. The appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2014 will be ratified if the votes cast “For” exceed the votes cast “Against.” Abstentions will have no effect on such vote.
Item 3 – Adoption of an Advisory Non-Binding Resolution to Approve Executive Compensation. The advisory resolution to approve executive compensation (“say on pay”) is non-binding. However, our Board of Directors will consider shareholders to have approved our executive compensation if the number of votes cast “For” the proposal exceeds the number of votes cast “Against” the proposal. Abstentions and broker non-votes will have no effect on such vote.
Is cumulative voting permitted for the election of directors?
In the election of directors, you may cumulate your vote. Cumulative voting allows you to allocate among the director nominees, as you see fit, the total number of votes equal to the number of director positions to be filled multiplied by the number of shares you hold. For example, if you own 100 shares of stock, and there are four directors to be elected at the annual meeting, you could allocate 400 “For” votes (four times 100) among as few or as many of the four nominees to be voted on at the annual meeting as you choose.
If you choose to cumulate your votes, you will need to submit a proxy card or a ballot and make an explicit statement of your intent to cumulate your votes, either by indicating in writing on the proxy card or by indicating in writing on your ballot when voting at the annual meeting. If you hold shares beneficially in street name and wish to cumulate votes, you should contact your broker, trustee or nominee.
How will my shares be voted if they are held in a broker’s name?
If you hold your shares through an account with a bank or broker, the bank or broker may vote your shares on some matters even if you do not provide voting instructions. Brokerage firms have the authority under the New York Stock Exchange ("NYSE") rules to vote shares on certain matters (such as the ratification of auditors) when their customers do not provide voting instructions. However, on most other matters when the brokerage firm has not received voting instructions from its customers, the brokerage firm cannot vote the shares on that matter and a “broker non-vote” occurs. This means that brokers may not vote your shares on the election of directors and the “say on pay” advisory vote if you have not given your broker specific instructions as to how to vote. Please be sure to give specific voting instructions to your broker so that your vote can be counted.
2 2 | PROXY What should I do now?
You should vote your shares by telephone, by the Internet or by returning your signed and dated proxy card in the enclosed envelope as soon as possible so that your shares will be represented at the annual meeting.
Who conducts the proxy solicitation and how much will it cost? PROXY STATEMENT We are asking for your proxy for the annual meeting and will pay all the costs of asking for shareholder proxies. We have hired Georgeson Inc. to help us send out the proxy materials and ask for proxies. Georgeson Inc.'s fee for these services is anticipated to be $7,500, plus out-of-pocket expenses. We can ask for proxies through the mail or by telephone, fax, or in person. We can use our directors, officers and employees to ask for proxies. These people do not receive additional compensation for these services. We will reimburse brokers and other custodians, nominees and fiduciaries for their reasonable out-of-pocket expenses for forwarding solicitation material to the beneficial owners of our common stock.
Can I revoke my proxy?
Yes. You can change your vote in one of four ways at any time before your proxy is used. First, you can enter a new vote by telephone or Internet. Second, you can revoke your proxy by written notice. Third, you can send a later dated proxy changing your vote. Fourth, you can attend the meeting and vote in person.
Who should I call with questions?
If you have questions about the annual meeting, you should call Roxann R. Basham, Vice President – Governance and Corporate Secretary, at (605) 721-1700.
When are the shareholder proposals due for the 2015 annual meeting?
In order to be considered for inclusion in our proxy materials, you must submit proposals for next year’s annual meeting in writing to our Corporate Secretary at our executive offices at 625 Ninth Street, Rapid City, South Dakota 57701, on or prior to November 20, 2014.
A shareholder who intends to submit a proposal for consideration, but not for inclusion in our proxy materials, must provide written notice to our Corporate Secretary in accordance with Article I, Section 9 of our Bylaws. In general, our Bylaws provide that the written notice must be delivered not less than 90 days nor more than 120 days prior to the first anniversary date of the immediately preceding annual meeting of shareholders. Our 2014 annual meeting is scheduled for April 29, 2014. Ninety days prior to the first anniversary of this date will be January 29, 2015, and 120 days prior to the first anniversary of this date will be December 30, 2014.
3 PROXY | 3 Proposal 1
ELECTION OF DIRECTORS
In accordance with our Bylaws and Article VI of our Articles of Incorporation, members of our Board of Directors are elected to three classes of staggered terms consisting of three years each. At this annual meeting of our shareholders, four directors will be elected to Class II of the Board of Directors to hold office for a term of three years until our annual meeting of shareholders in 2017, and until their respective successors shall be duly elected and qualified in accordance with our Bylaws.
Nominees for director at the annual meeting are David R. Emery, Rebecca B. Roberts, Warren L. Robinson and John B. Vering. All nominees are presently members of our Board of Directors. The proxies will vote your stock for the election of the four nominees for director, unless otherwise instructed. If, at the time of the meeting, any of such nominees are unable to serve in the capacity for which they are nominated or will not serve, events which the Board of Directors does not anticipate, it is the PROXY STATEMENT PROXY intention of the persons designated as proxies to vote, in their discretion, for such nominees as the Governance Committee may recommend and the Board of Directors may propose to replace those who are unable to serve.
The following information, including principal occupation or employment for the past five or more years and a summary of each individual’s experience, qualifications, attributes or skills that have led to the conclusion that each individual should serve as a director in light of our current business and structure, is furnished with respect to each nominee and each of the continuing members of the Board of Directors.
The Board of Directors recommends a vote FOR the election of the following nominees:
Class II – Nominees for Election until 2017 Annual Meeting
David R. Emery, 51, has been a director of the Company since 2004.
Chairman, President and Chief Executive Officer of Black Hills Corporation since 2005. Formerly held various positions with Black Hills Corporation, including President and Chief Executive Officer, President and Chief Operating Officer – Retail Business Segment and Vice President – Fuel Resources. Mr. Emery has 24 years of experience with Black Hills Corporation. Prior to joining us, he served as a petroleum engineer for a large independent oil and gas company.
Mr. Emery is our only employee currently on our Board. With over 20 years of experience at our Company, he has a deep knowledge and understanding of each of our business units and related industries. As an enrolled member of the Cheyenne River Sioux Tribe, Mr. Emery supports our Company’s interest in promoting diverse perspectives. He has demonstrated leadership abilities serving as our Chairman, President and Chief Executive Officer since 2005. His strategic, operational and industry knowledge and expertise provide the basis for critical leadership on the Board.
Rebecca B. Roberts, 61, has been a director of the Company since 2011.
Retired. Former President of Chevron Pipe Line Company, a pipeline company transporting crude oil, refined petroleum products, liquefied petroleum gas, natural gas and chemicals within the United States, from 2006 to February 2011. President of Chevron Global Power Generation from 2003 to 2006. Currently Director of Enbridge Energy Company, Inc. and Enbridge Energy Management, LLC since July 2012 and Mine Safety Appliances Company since October 2013.
Ms. Roberts has 37 years of experience in the energy industry. Her industry experience includes managing pipelines in North America and global pipeline projects; managing a portfolio of power plants in the United States, Asia and the Middle East; and work as a vice president, chemist, scientist and trader in the oil and gas sectors. She has also served on several other public company and non-profit boards in addition to those identified above. Her diversified energy industry experience and service on several public company and non-profit boards provide in-depth business and strategic acumen and diversity that strengthens our Board’s collective qualifications, skills and experiences.
4 4 | PROXY Warren L. Robinson, 63, has been a director of the Company since 2007.
Retired. Former Executive Vice President, Treasurer and Chief Financial Officer of MDU Resources Group, Inc., a diversified energy and resources company, from 1992 to January 2006.
Mr. Robinson has 29 years of experience in the utility industry, 18 of those years with MDU Resources Group. His industry
experience at MDU included regulated utility finance and operations and oil and gas exploration and production, two critical PROXY STATEMENT business segments for our Company. Mr. Robinson’s service as a chief executive for accounting and finance activities relating to our industries provides the necessary financial reporting expertise to serve as Chairman of our Audit Committee. His experience as an executive financial leader at a publicly traded energy company provides our Board with knowledge and understanding of the regulated business model and unique challenges of the geographic and regulatory environment in which we operate.
John B. Vering, 64, has been a director of the Company since 2005.
Managing Director of Lone Mountain Investments, Inc., oil and gas investments, since 2002. Partner in Vering Feed Yards LLC, a privately owned agricultural company, since 2010. Served as Interim President and General Manager of Black Hills Exploration and Production, Inc., our oil and gas subsidiary, from May 2010 to December 2011, pursuant to a consulting agreement, leading a strategic review of our oil and gas assets. Previously held several executive positions in the oil and gas industry.
Mr. Vering has over 30 years of experience, including executive leadership, in the oil and gas industry. He served for 23 years with Union Pacific Resources Company in several positions, including Vice President of Canadian Operations. He has direct operating experience in oil and gas transportation, marketing, and exploration and production, important business segments for our Company. His knowledge and understanding of the trans-national oil and gas business and his executive leadership experience strengthens our Board’s collective qualifications, skills and experiences.
Class III – Directors with Terms Expiring at 2015 Annual Meeting
Michael H. Madison, 65, has been a director since May 2012.
Retired. Former President and Chief Executive Officer and a Director of Cleco Corporation, a public utility holding company, from 2005 to 2011, and President and Chief Operating Officer of Cleco Power, LLC, from 2003 to 2005. He was state president, Louisiana-Arkansas with American Electric Power, from 2000 to 2003.
Mr. Madison has more than 40 years of utility industry experience in various positions of increasing responsibility including president, director, vice president of operations and engineering, vice president of engineering and production and vice president of corporate services. His knowledge of all aspects of the electric utility business, combined with his position as president and chief executive officer of a public company make him a valuable member of our Board of Directors with the necessary expertise to serve on our Audit Committee.
Steven R. Mills, 58, has been a director of the Company since 2011.
Retired. Former Chief Financial Officer of Amyris, Inc., an integrated renewable products company, from May 2012 to December 2013. Served as Senior Executive Vice President, Performance and Growth of Archer Daniels Midland Company, a processor, transporter, buyer and marketer of agricultural products from 2010 to February 2012, Executive Vice President and Chief Financial Officer from 2008 to 2010, and Senior Vice President Strategic Planning from 2006 to 2008.
Mr. Mills has more than 35 years of experience in the fields of accounting, corporate finance, strategic planning, and mergers and acquisitions. His extensive background in finance and accounting provides the necessary expertise to serve on our Audit Committee and provides financial and strategic acumen to strengthen our Board’s collective qualifications, skills and experience.
5 PROXY | 5 Stephen D. Newlin, 61, has been a director of the Company since 2004.
Chairman, President and Chief Executive Officer of PolyOne Corporation, a global provider of specialized polymer materials, services and solutions, since 2006. Former President, Industrial Sector, Ecolab, Inc., a global leader of services, specialty chemicals and equipment serving industrial and institutional clients, from 2003 to 2006. Served as President and a Director of Nalco Chemical Company, a manufacturer of specialty chemicals, services and systems, from 1998 to 2001 and Chief Operating Officer and Chairman from 2000 to 2001. Director of Oshkosh Corporation since January 2013 and formerly Director of Valspar Corporation from 2007 to February 2012.
Mr. Newlin has been a director of several other public company and non-profit boards in addition to those identified above. He has industry experience in chemicals, water treatment, power generation, mining, energy, petro-chemical and polymer compounds. Mr. Newlin’s experience as an active chairman and chief executive officer of a public company and experience on other public company boards provides an in-depth business, financial and strategic acumen that strengthens our Board’s PROXY STATEMENT PROXY collective qualifications, skills and experience and enables him to be an effective Governance Committee Chairman.
Class I – Directors with Terms Expiring at 2016 Annual Meeting
Jack W. Eugster, 68, has been a director of the Company since 2004.
Retired. Former Chairman, Chief Executive Officer and President of Musicland Stores, Inc., a retail music and home video company, from 1980 until his retirement in 2001. Currently Director of Graco Inc. since 2004 and Life Time Fitness, Inc. since 2009. Previously Director of Donaldson Co., Inc. from 1993 to 2012.
Mr. Eugster has been a director of several other public company and non-profit boards in addition to those identified above. He has experience as chairman and chief executive officer of a high-growth public company and other extensive experience on public company boards, including 11 years of service on the board of another regulated utility and five years of service as Non- Executive Chairman for Shopko Stores, Inc. His past experience lends special expertise relating to acquisitions, divestitures and finance. Mr. Eugster provides in-depth business, financial and strategic acumen that strengthens our Board’s collective qualifications, skills and experience and enables him to be an effective Compensation Committee Chairman.
Gary L. Pechota, 64, has been a director of the Company since 2007.
President and Chief Executive Officer of DT-TRAK Consulting, Inc., a medical billing services company, since 2007. Retired from 2005 to 2007. Former Chief of Staff of the National Indian Gaming Commission from 2003 to 2005. Previously held executive positions in the cement industry, including serving as chief executive officer of a publicly traded company, and positions in finance and accounting. Currently Director of Insteel Industries, Inc. since 1998. Previously Director of Texas Industries, Inc. from 2009 to 2012.
Mr. Pechota’s background in finance and accounting provides the necessary expertise to serve on our Audit Committee. As an enrolled member of the Rosebud Sioux Tribe, Mr. Pechota supports our Company’s interest in promoting diverse perspectives, as well as expertise relating to our business interests on tribal lands. In addition, his experience as an executive leader at several companies, his public company board experience, and his knowledge of mining and extracting minerals and the associated environmental issues strengthens our Board’s collective qualifications, skills and experiences.
Thomas J. Zeller, 66, has been a director of the Company since 1997.
Retired. Former Chief Executive Officer of RESPEC, a technical consulting and services firm with expertise in engineering, information technologies, and water and natural resources specializing in emerging environmental protection protocols, from January 2011 to August 2011 and served as President from 1995 to January 2011.
Mr. Zeller is currently Presiding Director of our Board of Directors and is a Past Chairman of our Audit Committee. His industry experience at RESPEC relates to many of our Company’s activities concerning technology, engineering and environmental matters. This expertise, in addition to his experience as an executive leader, provides valuable knowledge to our Board and strengthens its collective qualifications, skills and experiences relating to technical aspects of our Company operations and contract relationships.
6 6 | PROXY CORPORATE GOVERNANCE
Corporate Governance Guidelines. Our Board of Directors has adopted corporate governance guidelines titled “Corporate Governance Guidelines of the Board of Directors,” which guide the operation of our Board and assist the Board in fulfilling its obligations to shareholders and other constituencies. The guidelines lay the foundation for the Board’s responsibilities,
operations, leadership, organization and committee matters. The Governance Committee reviews the guidelines annually, and PROXY STATEMENT the guidelines may be amended at any time, upon recommendation by the Governance Committee and approval of the Board. These guidelines can be found in the “Governance” section of our website (www.blackhillscorp.com/corpgov.htm).
Board Independence. In accordance with New York Stock Exchange rules, the Board of Directors through its Governance Committee affirmatively determines the independence of each director and director nominee in accordance with guidelines it has adopted, which include all elements of independence set forth in the NYSE listing standards. These guidelines are contained in our Policy for Director Independence, which can be found in the “Governance” section of our website (www.blackhillscorp.com/corpgov.htm). Based on these standards, the Governance Committee determined that each of the following non-employee directors is independent and has no relationship with us, except as a director and shareholder:
Jack W. Eugster Michael H. Madison Rebecca B. Roberts Stephen D. Newlin Gary L. Pechota Thomas J. Zeller Warren L. Robinson Steven R. Mills
In addition, based on such standards, the Governance Committee determined that Messrs. Emery and Vering are not independent. Mr. Emery is not independent because he is our Chairman, President and Chief Executive Officer (“CEO”). Mr. Vering is not independent because he served as Interim President and General Manager of our oil and gas subsidiary during a portion of 2010 and 2011.
Board Leadership Structure. As noted above, our Board is currently comprised of ten directors, eight of whom are independent. Mr. Emery has served as our Chairman of the Board and CEO since 2005 and has been a member of our Board since 2004. Mr. Emery provides strategic, operational, and technical expertise and context for the matters considered by our Board. After considering alternative board leadership structures, our Board chose to retain the ability to balance an independent Board structure with the designation of an independent Presiding Director and to appoint as Chairman a CEO-Director with knowledge of and experience in the operations of our Company. At this time, our Board believes that having a single person serve as Chairman and CEO provides unified and responsible leadership for our Company and in conjunction with the Presiding Director provides the proper balance to ensure the Board receives the information, experience and direction it needs to effectively govern.
Our Board has and continues to value a high degree of Board independence. As a result, our corporate governance structure and practices promote a strong, independent Board and include several independent oversight mechanisms. Only independent directors serve on our Audit, Compensation and Governance Committees. Our Board believes these practices ensure that experienced and independent directors will continue to effectively oversee management and critical issues related to financial and operating plans, long-range strategic issues, enterprise risk and corporate integrity. All of our Board committees may seek legal, financial or other expert advice from a source independent of management.
Our Board annually appoints an independent Presiding Director. Thomas J. Zeller is our current Presiding Director and has served in this role since May 2010. The responsibilities of Presiding Director, as provided in the Board’s Governance Guidelines, are to chair executive sessions of the independent directors and communicate the Board’s annual evaluation of the CEO. The Presiding Director, together with the independent directors, establishes the agenda for executive sessions, which are held at each regular Board meeting. The Presiding Director serves as a liaison between the independent members of the Board and the CEO and discusses, to the extent appropriate, matters raised by the independent directors in executive session. The Presiding Director also consults with the Chairman regarding meeting agendas and presides over regular meetings of the Board in the absence of the Chairman. This leadership structure provides consistent and effective oversight of our management and our Company.
Risk Oversight. Our Board oversees an enterprise approach to risk management that supports our operational and strategic objectives. The Corporate Governance Guidelines of our Board of Directors provide that the Board will review major risks facing our Company and the options for risk mitigation presented by management. Our Board delegates oversight of certain risk considerations to its committees within each of their respective areas of responsibility; however, the full Board monitors 7 PROXY | 7 risk relating to strategic planning and execution, as well as executive succession. Financial risk oversight falls within the purview of our Audit Committee. Our Compensation Committee oversees compensation and benefit plan risks. Each committee reports to the full Board.
Our Board reviews any material changes in our key enterprise risk management ("ERM") issues with management at each quarterly Board meeting in conjunction with the presentation of quarterly financial results. In so doing, our Board seeks to ensure appropriate risk mitigation strategies are implemented by management on an ongoing basis. Operational and strategic plan presentations by management to our Board include consideration of the challenges and risks to our business. Our Board and management actively engage in discussions of these topics and utilize outside consultants as needed. Our Board oversees the assessment of our strategic plan risks as part of our strategic planning process. In addition, our Board periodically receives safety performance, environmental, legal and compliance reports.
Our Audit Committee oversees management’s strategy and performance relative to our significant financial risks. In PROXY STATEMENT PROXY consultation with management, the independent auditors and the internal auditors, the Audit Committee discusses our risk assessment, risk management and credit policies and reviews significant financial risk exposures along with steps management has taken to monitor, mitigate and report such exposures. At least twice a year, our Chief Risk Officer provides a Risk and Credit Report to the Audit Committee. We adopted a Credit Policy that establishes guidelines, controls and limits to manage and mitigate credit risk within established risk tolerances.
Our Compensation Committee adopted an executive compensation philosophy that provides the foundation for our executive compensation program. The executive compensation philosophy states that the executive pay program should be market-based and maintain an appropriate and competitive balance between fixed and variable pay elements, short-term and long-term compensation and cash and stock-based compensation. The Compensation Committee establishes company-specific performance goals with potential incentive payouts for our executive officers to motivate and reward performance, consistent with our long-term success. The target compensation for our senior officers is heavily weighted in favor of long-term incentives, aligning performance incentives with long-term results for our shareholders. Our Compensation Committee also sets minimum performance thresholds and maximum payouts in the incentive programs and maintains the discretion to reduce awards if excessive risk is taken. Stock ownership guidelines established for all of our officers require our executives to hold 100 percent of all shares awarded to them (net of share withholding for taxes and, in the case of cashless stock option exercises, net of the exercise price and withholding for taxes) until the established stock ownership guidelines are achieved. Our Compensation Committee also instituted “clawback” provisions in our incentive plans, which may require an executive to return incentives received, if the Compensation Committee determines, in its discretion, that the executive engaged in specified misconduct or wrongdoing or in the event of certain financial restatements.
Our management is responsible for day-to-day risk management and operates under an ERM program that addresses strategic, operational and financial risks. The ERM program includes practices to identify risks, assesses the impact and probability of occurrence, and develops action plans to prevent the occurrence or mitigate the impact of the risk. The ERM program includes regular reporting to our senior management team and includes monitoring and testing by Risk Management, Compliance and Internal Audit groups. The overall ERM program is reviewed with the Board of Directors on a regular basis.
We believe this division of risk management responsibilities described above is an effective approach for addressing the risks facing our Company.
Director Nominees. The Governance Committee uses a variety of methods for identifying and evaluating nominees for director. The Governance Committee regularly assesses the appropriate size of the Board and whether any vacancies on the Board are expected due to retirement or otherwise. In the event vacancies are anticipated, or otherwise arise, the Governance Committee considers various potential candidates for director. Board candidates are considered based upon various criteria, including diverse business, administrative and professional skills or experiences; an understanding of relevant industries, technologies and markets; financial literacy; independence status; the ability and willingness to contribute time and special competence to Board activities; personal integrity and independent judgment; and a commitment to enhancing shareholder value. The Governance Committee considers these and other factors as it deems appropriate, given the needs of the Board and us. Our goal is a balanced and diverse Board, with members whose skills, background and experience are complementary and, together, cover the spectrum of areas that impact our business. The Governance Committee considers candidates for Board membership suggested by a variety of sources, including current or past Board members, the use of third-party executive search firms, members of management and shareholders. Any shareholder may make recommendations for consideration by the Governance Committee for membership on the Board by sending a written statement of the qualifications of the recommended individual to the Corporate Secretary. There are no differences in the manner by which the Committee evaluates director candidates recommended by shareholders from those recommended by other sources.
8 8 | PROXY Shareholders who intend to nominate persons for election to the Board of Directors must provide timely written notice of the nomination in accordance with Article I, Section 9 of our Bylaws. Generally, our Corporate Secretary must receive the written notice at our executive offices at 625 Ninth Street, Rapid City, South Dakota, 57701, not less than 90 days nor more than 120 days prior to the anniversary date of the immediately preceding annual meeting of shareholders. The notice must set forth at a minimum the information set forth in Article I, Section 9 of our Bylaws, including the shareholder’s identity and status, contingent ownership interests, description of any agreement made with others acting in concert with respect to the nomination,
specific information about the nominee and supply certain representations by the nominee to us. PROXY STATEMENT
Communications with the Board. Shareholders and others interested in communicating directly with the Presiding Director, with the independent directors as a group, or the Board of Directors may do so in writing to the Presiding Director, Black Hills Corporation, 625 Ninth Street, Rapid City, South Dakota, 57701.
Corporate Governance Documents. The charters of the Audit, Compensation and Governance committees, as well as the Board’s Corporate Governance Guidelines, Policy for Director Independence, Code of Business Conduct and the Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Corporate Controller, and certain other persons performing similar functions can be found in the “Governance” section of our website (www.blackhillscorp.com/corp.gov.htm). We intend to disclose any amendments to, or waivers of the Code of Ethics on our website. Please note that none of the information contained on our website is incorporated by reference in this proxy statement.
Our Corporate Governance Guidelines include a plurality plus voting policy. Pursuant to the policy, any nominee for election as a director in an uncontested election who receives a greater number of votes “Withheld” from his or her election than votes “For” his or her election will promptly tender his or her resignation as a director to the Chairman of the Board following certification of the election results. Broker non-votes will not be deemed to be votes “For” or “Withheld” from a director’s election for purposes of the policy. The Governance Committee (without the participation of the affected director) will consider each resignation tendered under the policy and recommend to the Board whether to accept or reject it. The Board will then take the appropriate action on each tendered resignation, taking into account the Governance Committee’s recommendation. The Governance Committee in making its recommendation, and the Board in making its decision, may consider any factors or other information that it considers appropriate, including the reasons why the Committee believes shareholders “Withheld” votes for election from such director and any other circumstances surrounding the “Withheld” votes, any alternatives for curing the underlying cause of the “Withheld” votes, the qualifications of the tendering director, his or her past and expected future contributions to us and the Board, and the overall composition of the Board, including whether accepting the resignation would cause us to fail to meet any applicable SEC or NYSE requirements. The Board will publicly disclose by filing with the SEC on Form 8-K its decision and, if applicable, its rationale within 90 days after receipt of the tendered resignation.
Certain Relationships and Related Party Transactions. We recognize related party transactions can present potential or actual conflicts of interest and create the appearance that decisions are based on considerations other than the best interests of us and our shareholders. Accordingly, as a general matter, it is our preference to avoid related party transactions. Nevertheless, we recognize that there are situations where related party transactions may be in, or may not be inconsistent with, the best interests of us and our shareholders, including but not limited to situations where we may obtain products or services of a nature, quantity or quality, or on other terms, that are not readily available from alternative sources or when we provide products or services to related parties on an arm’s length basis on terms comparable to those provided to unrelated third parties or on terms comparable to those provided to employees generally. Therefore, our Board of Directors has adopted a policy for the review of related party transactions. This policy requires directors and officers to promptly report to our Vice President – Governance all proposed or existing transactions in which the Company and they, or persons related to them, are parties or participants. Our Vice President – Governance presents to our Governance Committee those transactions that may require disclosure pursuant to Item 404 of Regulation S-K (typically, those transactions that exceed $120,000). Our Governance Committee reviews the material facts presented and either approves or disapproves entry into the transaction. In reviewing the transaction, the Governance Committee considers the following factors, among other factors it deems appropriate: (i) whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances; (ii) the extent of the related party’s interest in the transaction; and (iii) the impact on a director’s independence in the event the related party is a director, an immediate family member of a director or an entity in which a director is a partner, shareholder or executive officer.
Section 16(a) Beneficial Ownership Reporting Compliance. Based solely upon a review of our records and copies of reports on Form 3, 4 and 5 furnished to us, we believe that during and with respect to 2013, all persons subject to the reporting requirements of Section 16(a) of the Securities Exchange Act of 1934, as amended, filed the required reports on a timely basis, except for Form 4s for Michael Madison, Director; Steven Mills, Director; and Thomas Zeller, Director, reporting the acquisition of shares through the Company's Director Optional Monthly Stock Purchase for the month of October 2013.
9 PROXY | 9 MEETINGS AND COMMITTEES OF THE BOARD
The Board of Directors
Our directors review and approve our strategic plan and oversee our management. Our Board of Directors held four in-person meetings and one telephonic meetings during 2013. Each regularly scheduled meeting of the Board includes an executive session of only independent directors. We encourage our directors to attend the annual shareholders’ meeting. During 2013, every director attended at least 75 percent of the combined total of Board meetings and Committee meetings on which the director served and all directors attended the 2013 annual meeting of shareholders.
Committees of the Board
Our Board has three standing committees to facilitate and assist the Board in the execution of its responsibilities. The PROXY STATEMENT PROXY committees are currently the Audit Committee, the Compensation Committee and the Governance Committee. In accordance with the NYSE listing standards and our Corporate Governance Guidelines, the Audit, Compensation and Governance Committees are comprised solely of independent directors. Each committee operates under a charter, which is available on our website at www.blackhillscorp.com/corpgov.htm and is also available in print to any shareholder who requests it. In addition, our Board creates special committees from time to time for specific purposes.
Members of the Committees are designated by our Board upon recommendation of the Governance Committee. The table below shows current membership for each of the Board committees.
Audit Committee Compensation Committee Governance Committee Michael H. Madison Jack W. Eugster* Jack W. Eugster Steven R. Mills Stephen D. Newlin Stephen D. Newlin* Gary L. Pechota Rebecca B. Roberts Gary L. Pechota Warren L. Robinson* Thomas J. Zeller Rebecca B. Roberts Thomas J. Zeller ______* Committee Chairperson
10 10 | PROXY Audit Committee. The Audit Committee held three in-person meetings and four telephonic meetings in 2013. The Audit Committee’s responsibilities, discussed in detail in its charter include, among other duties, the responsibility to:
• assist the Board in fulfilling its oversight responsibility to our shareholders relating to the quality and integrity of our accounting, auditing and financial reporting practices; • oversee the integrity of our financial statements, financial reporting process, systems of internal controls and
disclosure controls regarding finance, accounting and legal compliance; PROXY STATEMENT • review areas of potential significant financial risk to us; • review consolidated financial statements and disclosures; • appoint an independent registered public accounting firm for ratification by our shareholders; • monitor the independence and performance of our independent registered public accountants and internal auditing department; • pre-approve all audit and non-audit services provided by our independent registered public accountants; • review the scope and results of the annual audit, including reports and recommendations of our independent registered public accountants; • review the internal audit plan, results of internal audit work and our process for monitoring compliance with our Code of Conduct and other policies and practices established to ensure compliance with legal and regulatory requirements; and • periodically meet, in private sessions, with our internal audit group, Chief Financial Officer, Chief Compliance Officer, other management, and our independent registered public accounting firm.
In accordance with the rules of the NYSE, all of the members of the Audit Committee are financially literate. In addition, the Board determined that all of the members of the Audit Committee, Messrs. Madison, Mills, Pechota and Robinson, have the requisite attributes of an “audit committee financial expert” as provided in regulations promulgated by the SEC, and that such attributes were acquired through relevant education and/or experience.
Compensation Committee. The Compensation Committee held four in-person meetings and two telephonic meeting in 2013. All members of the Compensation Committee are independent directors as defined under NYSE listing standards and SEC rules. The Compensation Committee’s responsibilities, discussed in detail in its charter include, among other duties, the responsibility to:
• discharge the Board of Directors’ responsibilities related to executive and director compensation philosophy, policies and programs; • perform functions required of directors in the administration of all federal and state laws and regulations pertaining to executive employment and compensation; • consider and recommend for approval by the Board all executive compensation programs including executive benefit programs and stock ownership plans; and • promote an executive compensation program that supports the overall objective of enhancing shareholder value.
The Compensation Committee has authority under its charter to retain and terminate compensation consultants, outside counsel and other advisors as the Committee may deem appropriate in its sole discretion. The Committee has sole authority to approve related fees and retention terms and may delegate any of its responsibilities to subcommittees as the Committee may deem appropriate. In addition, pursuant to SEC rules and NYSE listing standards regarding the independence of compensation committee advisors, the Committee has the responsibility to consider the independence of any compensation advisor before engaging the advisor.
The Committee engaged Towers Watson, an independent consulting firm, to conduct an annual review of our 2013 total compensation program for executive officers and directors. The Committee reviewed the independence of Towers Watson and the individual representative of Towers Watson who serves as a consultant to the Committee, in accordance with the SEC and NYSE requirements and the specific factors that the requirements cite. The Compensation Committee concluded that Towers Watson is independent and Towers Watson's performance of services raises no conflict of interest. The Committee's conclusion was based in part on a report that Towers Watson provided to the Committee intended to reveal any potential conflicts of interest and a schedule provided by management of the type and amount of non-executive compensation services provided by Towers Watson to the Company. During 2013, management also purchased other services from Towers Watson. The cost of these services was less than $40,000.
The Committee annually evaluates the CEO’s performance against Board established goals and objectives, with input from the other independent directors. Based upon the Committee’s evaluation and recommendation, the independent directors of the Board set the CEO’s annual compensation, including salary, bonus, incentive and equity compensation. 11 PROXY | 11 The CEO annually reviews the performance of each of our executive officers and presents a summary of his evaluations to the Committee. Based upon these performance reviews, market analysis conducted by the compensation consultant and discussions with our Sr. Vice President, Chief Human Resources Officer, the CEO recommends the compensation of the executive officers to the Committee. The Committee may exercise its discretion in modifying any of the recommended compensation and award levels in its review and approval process.
More information describing the Compensation Committee’s processes and procedures for considering and determining executive compensation, including the role of our CEO and consultants in determining or recommending the amount or form of executive compensation, is included in the Compensation Discussion and Analysis.
In setting non-employee director compensation, the Compensation Committee recommends the form and amount of compensation to the Board of Directors, which makes the final determination. In considering and recommending the PROXY STATEMENT PROXY compensation of non-employee directors, the Compensation Committee considers such factors as it deems appropriate, including historical compensation information, level of compensation necessary to attract and retain non-employee directors meeting our desired qualifications and market data. In the review of director compensation for 2013, the Compensation Committee retained Towers Watson to provide market information on non-employee director compensation, including compensation structure, annual board and committee retainers, board and committee meeting fees, committee chairperson fees, number of Board meetings and stock-based compensation.
Compensation Committee Interlocks and Insider Participation. The Compensation Committee is comprised entirely of independent directors. In addition, none of our executive officers serve as a member of a board of directors or compensation committee of any entity that has one or more executive officers who serve on our Board or on our Compensation Committee.
Governance Committee. The Governance Committee held three in-person meetings in 2013. The Governance Committee’s responsibilities, discussed in detail in its charter include, among other duties, the responsibility to:
• assess the size of the Board and membership needs and qualifications for Board membership; • identify and recommend prospective directors to the Board to fill vacancies; • review and evaluate director nominations submitted by shareholders, including reviewing the qualifications and independence of shareholder nominees; • consider and recommend existing Board members to be renominated at our annual meeting of shareholders; • consider the resignation of an incumbent director who makes a principal occupation change (including retirement) or who receives a greater number of votes "Withheld" than votes "For" in an uncontested election of directors and recommend to the Board whether to accept or reject the resignation; • establish and review guidelines for corporate governance; • recommend to the Board for approval committee membership and the chairpersons of the committees; • recommend to the Board for approval an independent director to serve as a Presiding Director; • review the independence of each director and director nominee; • administer an annual evaluation of the performance of the Board and facilitate an annual assessment of each committee; and • ensure that the Board oversees the evaluation and succession planning of management.
DIRECTOR COMPENSATION
Director Fees
In 2013, our non-employee director compensation was as follows:
• Board cash retainer of $60,000; • common stock equivalents equal to $75,000 per year; • dividend equivalents on the common stock equivalents equal to the same dividend rate our shareholders receive; • committee member cash retainers of $10,000 for Audit Committee members, $7,500 for Compensation Committee members and $7,500 for Governance Committee members; • committee chair cash retainers of $10,000 for Audit Committee Chair, $8,000 for Compensation Committee Chair and $6,000 for Governance Committee Chair; and • Presiding Director cash retainer of $15,000. 12 12 | PROXY Effective January 1, 2014, our Presiding Director and Committee Chairpersons cash retainers were increased as follows:
• committee chair cash retainers of $12,500 for Audit Committee, $10,000 for Compensation Committee and $7,500 for
Governance Committee; and PROXY STATEMENT • Presiding Director cash retainer of $18,500.
Director Compensation for 2013 and Common Stock Equivalents Outstanding as of December 31, 2013(1)
Number of Common Fees Earned Stock Equivalents or Paid in Stock Outstanding at Name(2) Cash Awards(3) Total December 31, 2013(4) Jack W. Eugster $83,000 $75,000 $158,000 15,994 Michael H. Madison $70,000 $75,000 $145,000 2,513 Steven R. Mills $70,000 $75,000 $145,000 3,670 Stephen D. Newlin $81,000 $75,000 $156,000 16,243 Gary L. Pechota $77,500 $75,000 $152,500 13,010 Rebecca B. Roberts $75,000 $75,000 $150,000 4,544 Warren L. Robinson $80,000 $75,000 $155,000 13,208 John B. Vering $60,000 $75,000 $135,000 15,271 Thomas J. Zeller $90,000 $75,000 $165,000 19,696 ______(1) Our directors did not receive any stock option awards, non-equity incentive plan compensation, pension benefits or perquisites in 2013 and did not have any stock options outstanding at December 31, 2013.
(2) Mr. Emery, our CEO, is not included in this table because he is our employee and thus receives no compensation for his services as a director. Mr. Emery’s compensation received as an employee is shown in the Summary Compensation Table for our Named Executive Officers.
(3) Each non-employee director received a quarterly award of common stock equivalents with a grant date fair value of $18,750 per quarter or $75,000 a year. The grant date fair value of a common stock equivalent is the closing price of a share of our common stock on the grant date.
(4) The common stock equivalents are fully vested in that they are not subject to forfeiture; however, the shares are not issued until after the director ends his or her service on the Board. The common stock equivalents are payable in stock or cash or can be deferred further at the election of the director.
Director Stock Ownership Guidelines
Each member of our Board of Directors is required to apply at least 50 percent of his or her annual cash retainer toward the purchase of shares of common stock until the director has accumulated at least 7,500 shares of common stock or common stock equivalents. All of our directors have met their stock ownership guideline.
13 PROXY | 13 SECURITY OWNERSHIP OF MANAGEMENT AND PRINCIPAL SHAREHOLDERS
The following tables set forth the beneficial ownership of our common stock as of February 14, 2014 for each director, each executive officer named in the Summary Compensation Table, all of our directors and executive officers as a group and each person or entity known by us to beneficially own more than five percent of our outstanding shares of common stock. Beneficial ownership includes shares a director or executive officer has or shares the power to vote or transfer. There were no stock options outstanding for any of our directors or executive officers as of February 14, 2014.
Our directors and executive officers are prohibited from hedging our stock or holding our stock in a margin account and must receive permission from our Senior Vice President - General Counsel if they want to pledge our stock as collateral for a loan. None of our directors or executive officers have pledged stock. PROXY STATEMENT PROXY Except as otherwise indicated by footnote below, we believe that each individual or entity named has sole investment and voting power with respect to the shares of common stock indicated as beneficially owned by that individual or entity.
Shares of Directors Common Stock Common Beneficially Stock Name of Beneficial Owner(1) Owned(2) Equivalents(3) Total Percentage Directors Jack W. Eugster 17,000 15,994 32,994 * Michael H. Madison 7,165 2,513 9,678 * Steven R. Mills 10,224 3,670 13,894 * Stephen D. Newlin 5,042 16,243 21,285 * Gary L. Pechota 8,151 13,010 21,161 * Rebecca B. Roberts 4,744 4,544 9,288 * Warren L. Robinson 8,104 13,208 21,312 * John B. Vering 10,853 15,271 26,124 * Thomas J. Zeller 8,349 19,696 28,045 *
Named Executive Officers Anthony S. Cleberg 62,698 62,698 * David R. Emery 160,356 160,356 * Linden R. Evans 78,395 78,395 * Steven J. Helmers 56,042 56,042 * Robert A. Myers 31,958 31,958 *
All directors and executive officers as a group (15 persons) 492,796 104,149 596,945 1.3% ______* Represents less than one percent of the common stock outstanding.
(1) Beneficial ownership means the sole or shared power to vote, or to direct the voting of, a security or investment power with respect to a security.
(2) Includes restricted stock held by the following executive officers for which they have voting power but not investment power and stock underlying phantom stock units the executive officers have the right to acquire within 60 days as to which they have no current voting or investment power: Mr. Cleberg – 8,884 shares; Mr. Emery – 24,706 shares; Mr. Evans – 18,890 shares; Mr. Helmers – 6,042 shares; Mr. Myers – 4,932 shares and 4,979 phantom stock units; and all directors and executive officers as a group – 67,570 shares and 4,979 phantom stock units.
14 14 | PROXY (3) Represents common stock allocated to the directors’ accounts in the directors’ stock-based compensation plan, of which there are no voting rights.
Shares of Common Stock
Beneficially PROXY STATEMENT Name of Beneficial Owner Owned Percentage
Five Percent Shareholders
(1) BlackRock, Inc. 6,096,705 13.7% 40 East 52nd Street New York, NY 10022
(2) The Vanguard Group Inc. 3,305,588 7.4% 100 Vanguard Blvd. Malvern, PA 19355 ______(1) Information is as of December 31, 2013, and is based on a Schedule 13G filed on January 10, 2014. (2) Information is as of December 31, 2013, and is based on a Schedule 13G filed on February 11, 2014.
15 PROXY | 15 Proposal 2
RATIFICATION OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The firm of Deloitte & Touche LLP, independent registered public accountants, conducted the audit of Black Hills Corporation and its subsidiaries for 2013. Representatives of Deloitte & Touche LLP will be present at our annual meeting and will have the opportunity to make a statement, if they desire to do so, and to respond to appropriate questions.
Our Audit Committee has appointed Deloitte & Touche LLP to perform an audit of our consolidated financial statements and those of our subsidiaries for 2014 and to render their reports. The Board of Directors recommends ratification of the Audit Committee’s appointment of Deloitte & Touche LLP. The appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2014 will be ratified if the votes cast “For” exceed the votes cast “Against.” Abstentions will have PROXY STATEMENT PROXY no effect on such vote. If shareholder approval for the appointment of Deloitte & Touche LLP is not obtained, the Audit Committee will reconsider the appointment.
The Board of Directors recommends a vote FOR ratification of the appointment of Deloitte & Touche LLP to serve as our independent registered public accounting firm for 2014
FEES PAID TO THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The following table sets forth the aggregate fees for services provided to us for the years ended December 31, 2013 and 2012 by our independent registered public accounting firm, Deloitte & Touche LLP:
2013 2012
Audit Fees $2,100,000 $2,436,600 Audit-Related Fees 178,600 130,800 Tax Fees 323,600 550,800 Total Fees $2,602,200 $3,118,200
Audit Fees. Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports, opinions on the effectiveness of our internal control over financial reporting, and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the SEC.
Audit-Related Fees. Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported under “Audit Fees.” These services include internal control reviews; attest services that are not required by statute or regulation; employee benefit plan audits; due diligence, consultations and audits related to mergers and acquisitions; and consultations concerning financial accounting and reporting standards.
Tax Fees. Fees for services related to federal and state tax compliance planning and advice, including tax assistance with tax audits and review of tax returns.
The services performed by Deloitte & Touche LLP were pre-approved in accordance with the Audit Committee’s pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee will generally pre-approve a list of specific services and categories of services, including audit, audit-related, tax and other services, for the upcoming or current year, subject to a specified cost level. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.
16 16 | PROXY AUDIT COMMITTEE REPORT
In connection with the financial statements for the year ended December 31, 2013, the Audit Committee has (1) reviewed and discussed the audited financial statements with management; (2) discussed with Deloitte & Touche LLP, our independent registered public accounting firm (the “Auditors”), the matters required to be discussed by applicable Public Accounting Oversight Board Standards; and (3) received the written disclosures and letter from the Auditors required by applicable
requirements of the Public Company Accounting Oversight Board regarding the Auditors’ communications with the Audit PROXY STATEMENT Committee concerning independence, and has discussed with the Auditors their independence.
Based upon these reviews and discussions, the Audit Committee recommended to the Board that our audited consolidated financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2013 filed with the SEC.
THE AUDIT COMMITTEE
Warren L. Robinson, Chairperson Michael H. Madison Steven R. Mills Gary L. Pechota
17 PROXY | 17 EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS Introduction
This Compensation Discussion and Analysis describes our overall executive compensation policies and practices and specifically explains the compensation-related actions taken with respect to 2013 compensation for our executive officers included in the Summary Compensation Table (our “Named Executive Officers”). Our Named Executive Officers, based on 2013 positions and compensation levels, are:
• David R. Emery, Chairman, President and Chief Executive Officer ("CEO"); • Anthony S. Cleberg, Chief Financial Officer (“CFO”);
PROXY STATEMENT PROXY • Linden R. Evans, Chief Operating Officer (“COO”)-Utilities; • Steven J. Helmers, Sr. Vice President, General Counsel and Chief Compliance Officer ("Sr. V.P. - General Counsel"); and • Robert A. Myers, Sr. Vice President, Chief Human Resource Officer ("Sr. V.P. - Human Resources").
The Compensation Committee of the Board of Directors (the “Committee,” for purposes of this Compensation Discussion and Analysis) is composed entirely of independent directors and is responsible for approving and overseeing our executive compensation philosophy, policies and programs.
Executive Summary
Our long-term success depends on our operational excellence, providing reliable products and services to our customers and investing wisely for present and future shareholder return. To consistently achieve these outcomes we must attract, motivate and retain highly talented professionals. For these reasons, we promote an executive compensation program that supports the overall objective of enhancing shareholder value, based on principles designed to:
• attract, retain, motivate and encourage the development of highly qualified executives; • provide compensation that is competitive; • promote the relationship between pay and performance; • promote overall corporate performance that is linked to the interests of our shareholders; and • appropriately recognize and reward individual performance.
2013 Accomplishments
2013 was a strong year for Black Hills Corporation. Substantial progress was made on our strategic initiatives and we continued to lay a solid foundation for future earnings growth. Significant accomplishments for the year included:
• Achieved a 17 percent growth in earnings per share from continuing operations, as adjusted (1); • Improved our financial position and liquidity through a number of transactions, including: - Completed a $525 million public debt offering, the largest in our history, capturing favorable interest rates for 10 years while retiring higher cost debt and settling certain interest rate swaps; - Completed a $275 million two-year unsecured term loan at favorable terms, replacing other short-term debt; and - Achieved recognition of our improved financial condition and business risk profile from three leading credit rating agencies raising our corporate credit ratings to Baa1 with a stable outlook by Moody's Investor Service, BBB with a stable outlook by Standard & Poor's Ratings Agency and BBB with a positive outlook by Fitch Ratings; • Invested in our utility infrastructure and systems, improving the safe and reliable service our communities and utility customers depend on: - Commenced construction on our 132 megawatt Cheyenne Prairie Generating Station. Costs for plant construction and associated transmission are estimated at $222 million, and the project is currently within budget and on schedule for commercial operation in the fourth quarter of 2014; - Obtained approval of construction financing riders from the South Dakota and Wyoming utility commissions for the Cheyenne Prairie Generating Station, allowing recovery of financing costs during the construction period, thereby reducing long-term customer costs;
(1) Earnings per share from continuing operations, as adjusted is a non-GAAP measure. See Appendix A for a reconciliation of the non-GAAP measure to our results as reported under GAAP. 18 18 | PROXY - Received approval for a new 40 megawatt natural gas-fired turbine for our Colorado Electric utility with an estimated cost of $70 million planned for commercial operation in mid-2017; - Retired or prepared for retirement in early 2014 several of our smaller coal-fired and gas-fired generation units totaling 152 megawatts that were placed into service between 43 and 71 years ago; and - Achieved several notable operational performance metrics including 1st Quartile reliability ranking of our power
generation fleet compared to industry averages, power generation fleet availability of 97 percent and a safety PROXY STATEMENT performance total case incident rate of 1.7 compared to an industry average of 2.8; • Completed two horizontal wells in the Mancos Shale formation in the southern Piceance Basin earning approximately 20,000 net acres of Mancos Shale leasehold; • Increased the annual dividend for the 43rd consecutive year. Only two other electric or gas utility companies in the United States have a longer history of annual dividend increases; and • Rewarded by the stock market for our solid performance, recording industry-best stock price performance in 2013. Our one- and two-year total shareholder return was 47 percent and 65 percent, respectively, placing us at the top of our peer group and our three-year total shareholder return was 84 percent, placing us at the 94th percentile of our peer group.
2013 Performance Results
Our corporate financial goals are used as measures to determine awards under our variable pay programs. The following table summarizes our 2013 performance measures and results.
Pay Element Performance Measure 2013 Results
Short-term Incentive EPS from ongoing operations, $2.45 per share target of $2.31 Payout of 160% of Target
Long-term Incentive Total Shareholder Return (TSR) TSR 84% - Performance Share Award relative to our Peer Group 94th Percentile Ranking in Peer Group measured over a three-year period Maximum Payout of 175% of Target
Key Executive Compensation Objectives and 2013 Compensation Decisions
Overall, our goal is to target total direct compensation (the sum of base salary, short-term bonus incentives at target and long- term incentives at target) at the median of the appropriate market when our operating results approximate average performance in relation to our peers.
Our executive compensation is designed to maintain an appropriate and competitive balance between fixed and variable compensation components, short- and long-term compensation, and cash and stock-based compensation. The total target compensation mix for our Named Executive Officers in 2013 averaged:
• 40 percent fixed and 60 percent variable; • 60 percent base and short-term incentive and 40 percent long-term incentive; and • 50 percent cash and 50 percent equity.
We believe that the performance basis for determining compensation should differ by each reward component – base salary, short-term incentive and long-term incentive. Incentive measures (short-term and long-term) should emphasize objective, quantitative operating measures. The performance measures for our incentive compensation plans are as follows:
• Base Salary – Merit increases for our Named Executive Officers' base salary averaged 2.5 percent in 2013 based on the individual executive’s performance and to approximate the market median for comparable positions in our industry and peer group.
19 PROXY | 19 • Short-Term Incentive – The short-term incentive is based on earnings per share targets. The Committee believes that this performance measure closely aligns the executives’ and our shareholders’ interests and fosters teamwork and cooperation.
- The 2013 short-term target incentive opportunity was increased for our CEO from 80 percent to 90 percent, aligning with the market median of our industry and peer group. - The 2013 short-term target incentive remained the same as the prior year for our other Named Executive Officers. - Based on the attainment of pre-established performance goals, the actual payout can range from 50 percent to 200 percent of target. - The Committee selected an earnings per share goal based on ongoing operations of $2.31 as the 2013 corporate goal. - Our 2013 earnings for the Short-Term Incentive Plan were $2.45 per share exceeding our target earnings PROXY STATEMENT PROXY earnings per share goal by 6.1 percent, resulting in a payout of 160 percent of target.
• Long-Term Incentive – The long-term incentive is delivered 50 percent in restricted stock that vests ratably over a three-year service period and 50 percent in performance shares. Entitlement to the performance shares is based on our total shareholder return over a three-year performance period compared to our peer group. This performance measure was chosen because it mirrors the market return of our shareholders and compares our performance to that of our peer group.
Performance Share Plan Payment - Our total shareholder return for the three-year period, January 1, 2011 through December 31, 2013, was 84 percent, which ranked at the 94th percentile of our peer group, resulting in a maximum payout of 175 percent of target for our Named Executive Officers.
Restricted Stock Grant - Consistent with prior years, the Committee awarded 50 percent of the Named Executive Officers’ long-term incentive in restricted stock that ratably vests over three years.
We also have several governance programs in place to align our executive compensation with shareholder interests and to mitigate risks in our plans. These programs include stock ownership guidelines and clawback provisions in our short-term and long-term incentive award agreements.
In total, the Committee believes that the 2013 compensation actions, decisions and outcomes strongly reflect and reinforce our compensation philosophy and in particular emphasizes the alignment between compensation and both performance and shareholder interests. At our 2013 annual meeting, shareholders owning 94.1 percent of the shares voted on this matter approved our executive compensation for 2012, which we consider highly supportive of our current compensation philosophy. In connection with establishing the 2013 executive compensation program, the Board reviewed the results of the say on pay vote, as well as market data and performance indicators. No significant design changes were made.
Setting Executive Compensation
Based upon our compensation philosophy, the Committee structures our executive compensation to motivate our officers to achieve specified business goals and to reward them for achieving such goals. The key steps the Committee follows in setting executive compensation are to:
• analyze executive compensation market data to ensure market competitiveness; • review the components of executive compensation, including base salary, short-term incentive, long-term incentive, retirement and other benefits; • review total compensation mix and structure; and • review executive officer performance, responsibilities, experience and other factors cited above to determine individual compensation levels.
Market Compensation Analysis
The market for our senior executive talent is national in scope and is not focused on any one geographic location, area or region of the country. As such, our executive compensation should be competitive with the national market for senior
20 20 | PROXY executives. It should also reflect the executive’s responsibilities and duties and align with the compensation of executives at companies or business units of comparable size and complexity. The Committee gathers market information for our corporate executives from the electric and gas utility industry and also reviews general industry data as an additional reference.
The Committee selects and retains the services of an independent consulting firm to periodically: • provide information regarding practices and trends in compensation programs;
• review and evaluate our compensation program as compared to compensation practices of other companies with PROXY STATEMENT similar characteristics, including size and type of business; • review and assist with the establishment of a peer group of companies; and • provide a compensation analysis of the executive positions.
The Committee used the services of Towers Watson to evaluate 2013 compensation. Towers Watson gathered data from nationally recognized survey providers, as well as specific peer companies through public filings, which included: • Towers Watson’s 2012 Compensation Data Bank (energy services and general industry); and • 22 peer companies representing the utility and energy industry.
The 22 peer companies ranged in revenue size from approximately $900 million to $4.1 billion with the median at $1.7 billion. These are the same companies the Committee chose for our peer group for our 2012 to 2014 and 2013 to 2015 Performance Share Plans. The survey data were adjusted for our size using either regression analysis or tabular data from companies with annual revenues between $1.0 billion and $3.0 billion.
Our peer companies included in the analysis for 2013 compensation decisions were:
Alliant Energy Corp MDU Resources Group, Inc. Portland General Electric Co. ALLETE Inc. National Fuel Gas Co. Questar Corp. Avista Corp NorthWestern Corporation Southwest Gas Corp. CH Energy Group Inc. NV Energy, Inc. UIL Holdings Corp. Cleco Corporation OGE Energy Corp. UniSource Energy Corp. GenOn Energy Inc. Piedmont Natural Gas Vectren Corporation Great Plains Energy Incorporated PNM Resources, Inc. Westar Energy Inc. IDACORP, Inc. (CH Energy Group Inc., GenOn Energy, Inc. and NV Energy, Inc. were subsequently acquired by other companies and therefore are no longer included in our peer group for incentive plan purposes and future compensation market analysis.)
The salary surveys are one of several factors the Committee uses in setting appropriate compensation levels. Other factors include company performance, individual performance and experience, the level and nature of the executive’s responsibilities, and discussions with the CEO related to the other officers.
Components of Executive Compensation
The components of our executive compensation program consist of a base salary, a short-term incentive plan, and a long-term incentive award program. In addition, we provide income for our officers’ retirement and other benefits.
An important component of the total compensation is derived from incentive compensation. Incentive compensation is intended to motivate and encourage our executives to drive performance and achieve superior results for our shareholders. The Committee periodically reviews information provided by the compensation consultant to determine the appropriate level and mix of incentive compensation. Actual income in the form of incentive compensation is realized by the executive as a result of achieving Company goals and overall stock performance. The Committee believes that a significant portion of total target compensation should be comprised of incentive compensation. In order to reward long-term growth while still encouraging short-term results, the Committee establishes incentive targets that emphasize long-term compensation at a greater level than short-term compensation.
The Committee annually reviews all components of each senior executive officer’s compensation, including salary, short-term incentive, equity and other long-term incentive compensation values granted, and the current and potential value of the executive officer’s total Black Hills Corporation equity holdings.
21 PROXY | 21 The components of total target compensation in 2013 were as follows:
Base Short-Term Long-Term Salary Incentive Incentive David R. Emery, CEO 30% 26% 44% Anthony S. Cleberg, CFO 38% 20% 42% Linden R. Evans, COO-Utilities 39% 25% 36% Steven J. Helmers, Sr. V.P. - General Counsel 43% 20% 37% PROXY STATEMENT PROXY Robert A. Myers, Sr. V.P. - Human Resources 48% 19% 33%
Base Salary. Base salaries for all officers are reviewed annually. We also adjust the base salary of our executives at the time of a promotion or change in job responsibility, as appropriate. Evaluation of 2013 base salary adjustments occurred in January 2013. The Committee approved base salary increases for our Named Executive Officers averaging 2.5 percent. The base salary component of each position was compared to the median of the market data provided by the compensation consultant. The actual base salary of each officer was determined by the executive’s performance, the experience level of the officer, the executive’s current position in a market-based salary range, and internal pay relationships.
Short-Term Incentive. Our Short-Term Incentive Plan is designed to recognize and reward the contributions of individual executives as well as the contributions that group performance makes to overall corporate success. The program’s goal for our corporate officers is based on earnings per share targets in order to closely align interests with shareholders and to foster teamwork and cooperation within the officer team. The short-term incentive, after applicable tax withholding, is distributed to the officer in the form of 50 percent stock and 50 percent cash, unless the officer has met his or her stock ownership guideline, in which case he or she may elect to receive the total award in cash, after deductions and applicable tax withholding. Target award levels are established as a percentage of each participant’s base salary. A target award is typically comparable to the average short-term incentive payout award of the peer group at the 50th percentile level. The actual payout will vary, based on performance, between zero and 200 percent of the individual executive’s short-term incentive target award level.
The Committee approves the target level for each officer in January, which applies to performance in the upcoming plan year. Target levels are derived in part from competitive data provided by the compensation consultant and in part by the Committee’s judgment regarding internal equity, retention and an individual executive’s expected contribution to the achievement of our strategic objectives. The target levels for the positions held by our Named Executive Officers in 2013 are shown below:
Short-term Incentive Target (Percentage of Base Salary) David R. Emery, CEO 90% Linden R. Evans, COO-Utilities 65% Anthony S. Cleberg, CFO 50% Steven J. Helmers, Sr. V.P. - General Counsel 45% Robert A. Myers, Sr. V.P. - Human Resources 40%
The threshold, target and maximum payout levels for our Named Executive Officers under the 2013 Short-Term Incentive Plan are shown in the Grants of Plan Based Awards in 2013 table on page 31, under the heading “Estimated Future Payouts Under Non-Equity Incentive Plan Awards.”
Early in the first quarter, the Committee meets to establish the goals for the current plan year, to evaluate actual performance in relation to the prior year’s targets and to approve the actual payment of awards related to the prior plan year. The Committee reserves the discretion to adjust any award, and will review and take into account individual performance, level of contribution, and the accomplishment of specific project goals that were initiated throughout the plan year.
22 22 | PROXY The Committee selected an earnings per share goal based on ongoing operations for 2013. This meets the objectives of the plan, including:
• aligns the interests of the plan participants and the shareholders with a corporate-wide component;
• motivates employees and supports the corporate compensation philosophy; PROXY STATEMENT • provides an incentive reflective of core operating performance by adjusting for unique one-time events; • easily understood and communicated to ensure “buy-in” from the participants; and • meets the performance objectives of the plan, to achieve over time an average payout equal to market competitive levels.
The Committee approved the goals for 2013 for the corporate officers as follows:
Earnings Per Share from Threshold Ongoing Operations Payout % of Target Minimum $2.08 50% Target $2.31 100% Maximum $2.54 200%
On January 29, 2014, the Committee approved a payout of 160 percent of target under the 2013 Short-Term Incentive Plan based on the attainment of $2.45 earnings per share from ongoing operations. Earnings from ongoing operations were calculated by adjusting earnings from continuing operations for unique events to reflect core operating performance and is consistent with our adjusted income from continuing operations, a non-GAAP measure (see Appendix A), reported externally to our investors, as shown below:
Earnings per share from continuing operations $2.61 Adjustments for unique items: Non-cash, mark-to-market gain on certain interest rate swaps (0.44) Settlement of interest rate swaps associated with Black Hills Wyoming Project Debt and write-off of deferred financing cost, net of interest savings 0.15 Financing costs relating to early repayment of $250 million bonds, net of interest savings 0.13
$2.45
The 2013 award, after applicable tax withholding, was distributed in the form of 100 percent cash to all of our Named Executive Officers because they had all met their stock ownership guidelines and elected to receive their 2013 award in the form of 100 percent cash. Payouts for corporate officers under the Short-Term Incentive Plan have varied significantly over the last five years, as shown below:
Plan Year Payout % of Target 2013 160% 2012 184% 2011 66% 2010 160% 2009 56%
Actual awards made to each of our Named Executive Officers under the Short-Term Incentive Plans for 2013 are included in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 29.
23 PROXY | 23 Long-Term Incentive. Long-term incentive compensation is comprised of grants made by the Committee under our 2005 Omnibus Incentive Plan (“Omnibus Incentive Plan”), which was previously approved by our shareholders. Long-term incentive compensation is intended to:
• promote corporate goals by linking the personal interests of participants to those of our shareholders; • provide participants with an incentive for excellence in individual performance; • promote teamwork among participants; and • motivate, retain, and attract the services of participants who make significant contributions to our success by allowing participants to share in such success.
The Committee oversees the administration of the Omnibus Incentive Plan with full power and authority to determine when and to whom awards will be granted, along with the type, amount and other terms and conditions of each award. The long- term incentive compensation component is currently composed of restricted stock (or restricted stock units if the executive PROXY STATEMENT PROXY elects to defer the compensation) and performance shares. The Committee chose these components because linking executive compensation to stock price appreciation and total shareholder return is an effective way to align the interests of management with those of our shareholders. The Committee selected total shareholder return as the performance goal for the performance shares because it believes executive pay under a long-term, capital accumulation program should mirror our performance in shareholder return as compared to our peer group of companies.
The value of long-term incentives awarded is based primarily on competitive market-based data presented by the compensation consultant to the Committee, the impact each position has on our shareholder return and internal pay relationships. The Committee approved the target long-term incentive compensation level for each officer in January 2013.
Long-term incentive compensation approved for 2013 for our Named Executive Officers is shown in the table below:
Long-Term Percentage Incentive of Base Value Salary David R. Emery, CEO $ 1,040,000 150% Anthony S. Cleberg, CFO $ 400,000 110% Linden R. Evans, COO-Utilities $ 400,000 93% Steven J. Helmers, Sr. V.P. - General Counsel $ 270,000 85% Robert A. Myers, Sr. V.P. - Human Resources $ 220,000 70%
The variance in percentage of base salary for the long-term incentive value of our Named Executive Officers reflects our philosophy that certain officers should have more of their total compensation at risk because they hold positions that have a greater impact on our long-term results.
Restricted stock (or restricted stock units) is used to deliver 50 percent of the long-term incentive award amounts, with the remaining 50 percent delivered in the form of performance shares. The actual shares of restricted stock and performance shares granted in 2013 are reflected in the tables in the Restricted Stock and Restricted Stock Units and Performance Shares sections that follow.
Restricted Stock and Restricted Stock Units. Restricted stock and restricted stock units awarded as long-term incentives vest one-third each year over a three-year period, and automatically vest in their entirety upon death, disability or a change in control. Dividends are paid on the restricted stock and dividend equivalents accrue on restricted stock units. Unvested restricted stock or units are forfeited if an officer’s employment is terminated for any reason other than death, disability or in the event of a change in control. Corporate officers may elect to receive the award in the form of restricted stock, or to defer the payment under the Nonqualified Deferred Compensation Plan in the form of restricted stock units. The number of shares awarded in 2013 for each of our Named Executive Officers is shown below and is included in the Grants of Plan Based Awards in 2013 table under the heading “All Other Stock Awards: Number of Shares of Stock or Units” and “Grant Date Fair Value of Stock Awards” on page 31.
24 24 | PROXY Shares of Restricted Stock Granted David R. Emery. CEO 12,874 Anthony S. Cleberg, CFO 4,952 Linden R. Evans, COO-Utilities 4,952
Steven J. Helmers. Sr. V.P. - General Counsel 3,342 PROXY STATEMENT Robert A. Myers, Sr. V.P. - Human Resources 2,723
Performance Shares. Participants are awarded a target number of performance shares based upon the value of the individual performance share component approved by the Committee, divided by the Beginning Stock Price. The Beginning Stock Price, as defined under the Performance Plan, is the average of the closing price of our common stock for the 20 trading days immediately preceding the beginning of the plan period. Entitlement to performance shares is based on our total shareholder return over designated performance periods, as measured against our peer group. The peer group for our performance plan is the same as our peer group used for our market compensation analysis and is listed on page 21. In addition, in order for any performance shares to be awarded, the Ending Stock Price (20-day average) must be at least equal to 75 percent of the Beginning Stock Price. The final value of the performance shares is based upon the number of shares of common stock that are ultimately granted, based upon our performance in relation to the performance criteria.
The Committee, with the guidance of Towers Watson, periodically conducts a review of the market competitiveness of our Performance Share Plan. The last study was done in late 2011 which resulted in a broadening of the pay/performance range beginning with the 2012 to 2014 performance period. A summary of the performance criteria for each performance period outstanding as of December 31, 2013 is summarized in the table below.
Percentile Ranking for Percentile Ranking for Percentile Ranking Performance Plan Threshold Payout of Threshold Payout of for Maximum Possible Payout Range Period 50% of Target Shares 100% of Target Shares Payout Level of Target
2013-2015 Plan 30th percentile 50th percentile 85th percentile 0-200% 2012-2014 Plan 30th percentile 50th percentile 85th percentile 0-200% 2011-2013 Plan 40th percentile 50th percentile 80th percentile 0-175%
The performance awards and dividend equivalents, if earned, are paid in 50 percent cash and 50 percent common stock. All payroll deductions and applicable tax withholding related to the award are withheld from the cash portion. Performance share target grant values for new performance periods are approved in January of each year.
Each performance share period extends for three years. For the recently completed performance period, January 1, 2011 to December 31, 2013, our total shareholder return was 84 percent, which ranked at the 94th percentile of our peer group, resulting in the maximum payout of 175 percent target. The actual shares, cash, and total payout value awarded to our Named Executive Officers for the performance period are shown below and are included in the Equity Incentive Plan Awards column of the Outstanding Equity Awards at Fiscal Year-End 2013 table on page 32.
Equivalent 50% Awarded 50% Awarded Total Shares Earned in Shares in Cash Payout Value David R. Emery. CEO 25,032 12,516 $643,224 $1,286,421 Anthony S. Cleberg, CFO 10,951 5,475 $281,412 $562,773 Linden R. Evans, COO-Utilities 12,516 6,258 $321,612 $643,210 Steven J. Helmers. Sr. V.P. - General Counsel 8,448 4,224 $217,079 $434,150 Robert A. Myers, Sr. V.P. - Human Resources 6,259 3,129 $160,855 $321,654
25 PROXY | 25 Payouts under the Performance Share Plan have varied significantly over the last five years, as shown below:
Performance Period Payout % of Target January 1, 2011 to December 31, 2013 175 January 1, 2010 to December 31, 2012 171 January 1, 2009 to December 31, 2011 — January 1, 2008 to December 31, 2010 — January 1, 2007 to December 31, 2009 —
Target shares for each of our Named Executive Officers for the outstanding performance periods are as follows:
PROXY STATEMENT PROXY January 1, 2012 January 1, 2013 to to December 31, 2014 December 31, 2015 Performance Period Performance Period David R. Emery, CEO 13,262 14,436 Anthony S. Cleberg, CFO 6,062 5,552 Linden R. Evans, COO-Utilities 6,062 5,552 Steven J. Helmers. Sr. V.P. - General Counsel 4,092 3,748 Robert A. Myers, Sr. V.P. - Human Resources 3,334 3,054
Actual payouts, if any, will be determined based upon our total shareholder return for the plan period in comparison to our peer group.
Performance Evaluation
Role of Executive Officers in Compensation Decisions. The CEO annually reviews the performance of each of our executive officers and presents a summary of his evaluations to the Committee. Based upon these performance reviews, market analysis conducted by compensation consultants and discussions with our Sr. V.P. - Human Resources, the CEO recommends the compensation for this group of officers to the Committee.
Role of the Committee and Board in Setting Executive Compensation. The Committee reviews and establishes the Company’s financial targets and the CEO’s goals and objectives for the year. After the end of each year, the Committee evaluates the CEO’s performance in light of established goals and objectives, with input from the other independent directors. Based upon the Committee’s evaluation and recommendation, the independent directors of the Board set the CEO’s annual compensation, including salary, short-term incentive, long-term incentive and equity compensation.
The Committee reviews the CEO’s evaluation of the performance of our senior officers. The Committee may approve the CEO’s compensation recommendations for this group of officers or exercise its discretion in modifying any of the recommended compensation and award levels in its review and approval process. The Committee is required to approve all decisions regarding equity awards to our officers.
Stock Ownership Guidelines
The Committee has implemented stock ownership guidelines that apply to all officers based upon their level of responsibility. We believe it is important for our officers to hold a significant amount of our common stock to further align their performance with the interest of our shareholders. A “retention ratio” approach to stock ownership is incorporated into the guidelines. Officers are required to retain 100 percent of all shares owned, including shares awarded through our incentive plans (net of share withholding for taxes and, in the case of cashless stock option exercises, net of the exercise price and withholding for taxes) until specific ownership goals are achieved. Ownership guidelines are denominated in share amounts that approximate a multiple of base salary.
26 26 | PROXY The ownership guidelines and current stock ownership of our Named Executive Officers as of February 14, 2014, are shown below: Ownership Actual Years Guideline Ownership in Officer Level (# of Shares) (# of Shares) Position PROXY STATEMENT David R. Emery, CEO 90,000 160,356 10 Anthony S. Cleberg, CFO 40,000 62,698 5 Linden R. Evans, COO-Utilities 40,000 78,395 9 Steven J. Helmers. Sr. V.P. - General Counsel 25,000 56,042 13 Robert A. Myers, Sr. V.P. - Human Resources 25,000 31,958 5
2013 Benefits
Retirement Benefits. We maintain a variety of employee benefit plans and programs in which our executive officers may participate. We believe it is important to provide post-employment benefits to our executive officers and the benefits we provide approximate retirement benefits paid by other employers to executives in similar positions. The Committee periodically reviews the benefits provided, with assistance from its compensation consultant, to maintain a market-based benefits package. None of our Named Executive Officers received any pension benefit payments in 2013.
Effective January 1, 2010, we adopted a defined contribution plan design as our primary retirement plan and amended our Defined Benefit Pension Plan (“Pension Plan”) for all eligible employees to incorporate a partial freeze in which the accrual of benefits ceased for certain participants while other participants were allowed an election to continue to accrue benefits. Mr. Emery is our only Named Executive Officer who met the age and service requirement allowing him to continue to accrue benefits under the Pension Plan. Employees whom no longer accrue benefits under the Pension Plan now receive Company Retirement Contributions (“Retirement Contributions”) in the Retirement Savings Plan. The Retirement Contributions are an age and service points-based calculation.
The 401(k) Retirement Savings Plan is offered to all our eligible employees and we provide matching contributions for certain eligible participants. All of our Named Executive Officers are participants in the 401(k) Retirement Savings Plan and received matching contributions in 2013. The matching contributions and the Retirement Contributions are included as “All Other Compensation” in the Summary Compensation Table on page 29.
We also provide Nonqualified Plans to certain officers because of Internal Revenue Code limitations imposed on the qualified plans. The level of retirement benefits provided by the Pension Plan and Nonqualified Plans for each of our Named Executive Officers is reflected in the Pension Benefits for 2013 table on page 34. Our contributions to the Nonqualified Deferred Compensation Plan are included in the All Other Compensation column of the Summary Compensation Table on page 29 and the aggregate Nonqualified Deferred Compensation balance at December 31, 2013 is reported in the Nonqualified Deferred Compensation for 2013 table on page 37. These retirement benefits are explained in more detail in the accompanying narrative to the tables.
Other Personal Benefits. We provide the personal use of a Company vehicle and limited reimbursement of financial planning services as benefits to our executive officers. The specific amount attributable to these benefits in 2013 is disclosed in the Summary Compensation Table on page 29. The Committee periodically reviews the other personal benefits provided to our executive officers and believes the current benefits are reasonable and consistent with our overall compensation program.
Change in Control Payments
Our Named Executive Officers may also receive severance benefits in the event of a change in control. We have no employment agreements with our Named Executive Officers. However, change in control agreements are common among our peer group and the Committee and our Board of Directors believe providing these agreements to our corporate officers protects our shareholder interests in the event of a change in control by helping assure management focus and continuity. Our change in control agreements have expiration dates and our Board of Directors conducts a thorough review of the change in control agreements at each renewal period. The Board conducted a review of the agreements in 2013 and entered into new agreements with the senior executive officers replacing the agreements that expired on November 15, 2013. The new agreements are substantially the same as the prior agreements with the addition of non-competition, non-solicitation and non-
27 PROXY | 27 disparagement provisions. The new agreements expire November 15, 2016. In general, our change in control agreements provide a severance payment of up to 2.99 times average compensation for our CEO, and up to two times average compensation for the other Named Executive Officers. The change in control agreements do not provide for excise tax gross- ups and contain a “double trigger,” providing benefits in association with
(1) a change in control, and (2) (i) a termination of employment other than by death, disability or by us for cause, or (ii) a termination by the employee for good reason.
See the Potential Payments upon Termination or Change in Control table on page 38 and the accompanying narrative for more information regarding our change in control agreements and estimated payments associated with a change in control.
PROXY STATEMENT PROXY Tax and Accounting Implications
Section 162(m) of the U.S. Internal Revenue Code of 1986, as amended, limits the tax deductibility by a corporation of compensation in excess of $1 million paid to certain of its officers. Compensation which qualifies as “performance-based” is excluded from the $1 million limit, if, among other requirements, the compensation is payable only upon attainment of pre- established, objective performance goals under a plan approved by the corporation’s shareholders. Our 2005 Omnibus Incentive Plan is structured so that short-term and long-term, cash and equity awards granted under that plan may qualify as performance based compensation. The Compensation Committee generally manages a large share of our incentive compensation for our Named Executive Officers to qualify for the “performance-based” exemption. However, the Compensation Committee has the discretion to design and use compensation elements and awards that may not be deductible under Section 162(m) if it determines those elements are in line with competitive practice, our compensation philosophy, and our best interests.
Clawback Policy
We have a policy that if an accounting restatement occurs after incentive payments have been made, due to the results of misconduct associated with financial reporting, the Committee will seek repayment of the incentive compensation from our CEO and CFO, and the Committee has the discretion to request repayment of incentive compensation from our other officers, taking into consideration the individual roles and responsibilities prompting the restatement.
In addition, our award agreements for restricted stock and target performance shares include clawback provisions whereby the participant may be required to repay all income or gains previously realized in respect of such awards if his or her employment is terminated for cause, or if, within one year following termination of employment, the Board determines that the participant engaged in conduct prior to his or her termination that would have constituted the basis for a termination of employment for cause.
COMPENSATION COMMITTEE REPORT
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to our Board of Directors that the Compensation Discussion and Analysis be included in this proxy statement.
THE COMPENSATION COMMITTEE
Jack W. Eugster, Chairperson Stephen D. Newlin Rebecca B. Roberts Thomas J. Zeller
28 28 | PROXY SUMMARY COMPENSATION TABLE
The following table sets forth the total compensation paid or earned by each of our Named Executive Officers for the years ended December 31, 2013, 2012 and 2011. We have no employment agreements with our Named Executive Officers. PROXY STATEMENT
Changes in Pension Value and Nonqualified Non-Equity Deferred All Name and Incentive Plan Compensation Other Principal Position Year Salary(1) Stock Awards(2) Compensation(3) Earnings (4) Compensation(5) Total David R. Emery 2013 $689,650 $1,037,511 $996,155 $— $64,294 $2,787,610 Chairman, President 2012 $696,000 $865,325 $994,042 $713,494 $61,484 $3,330,345 and Chief Executive Officer 2011 $638,462 $741,037 $341,803 $1,263,510 $61,133 $3,045,945 Anthony S. Cleberg 2013 $361,188 $399,050 $289,848 $— $231,882 $1,281,968 Executive Vice 2012 $364,385 $395,577 $325,343 $6,213 $170,984 $1,262,502 President and Chief Financial Officer 2011 $336,538 $324,175 $111,743 $9,640 $229,078 $1,011,174 Linden R. Evans 2013 $428,481 $399,050 $446,992 $— $308,013 $1,582,536 President and Chief 2012 $429,231 $745,571 $501,800 $37,910 $209,319 $1,923,831 Operating Officer – Utilities 2011 $383,077 $370,519 $153,812 $58,978 $223,235 $1,189,621 Steven J. Helmers 2013 $316,300 $269,349 $228,444 $— $112,303 $926,396 Sr. Vice President – 2012 $318,461 $267,016 $256,414 $138,731 $85,824 $1,066,446 General Counsel 2011 $291,538 $250,095 $77,563 $249,809 $96,448 $965,453 Robert A. Myers 2013 $312,219 $219,468 $200,442 $— $192,092 $924,221 Sr. Vice President – 2012 $315,230 $217,543 $224,983 $— $144,391 $902,147 Human Resources 2011 $292,000 $185,257 $77,563 $— $173,436 $728,256
(1) Salary represents the actual salary paid to the Named Executive Officer for each calendar year. The year 2012 contained 27 bi-weekly payment dates rather than the normal 26 bi-weekly payment dates. If 2012 salary data were adjusted to reflect only 26 payment dates the amounts would be: Emery - $671,000, Cleberg - $351,308, Evans - $414,231, Helmers - $307,115, and Myers - $303,884.
(2) Stock Awards represent the grant date fair value related to restricted stock and performance shares that have been granted as a component of long-term incentive compensation. The grant date fair value is computed in accordance with the provisions of accounting standards for stock compensation. Assumptions used in the calculation of these amounts are included in Note 11 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2013. The amount included for performance shares is based on a payout of 100 percent of target, the level the award is expected to payout as determined as of the grant date. If the award were based on the maximum payout level, the amounts for the Stock Awards column would be increased to the following amounts:
2013 2012 2011 David R. Emery $1,555,042 $1,293,157 $996,808 Anthony S. Cleberg $598,090 $591,137 $436,067 Linden R. Evans $598,090 $941,132 $498,404 Steven J. Helmers $403,715 $399,024 $336,414 Robert A. Myers $328,954 $325,098 $249,209
29 PROXY | 29 (3) Non-Equity Incentive Plan Compensation represents amounts earned under the Short-Term Incentive Plan. The Compensation Committee approved the payout of the 2013 awards at its January 29, 2014 meeting, and the awards were paid on February 28, 2014.
(4) Change in Pension Value and Nonqualified Deferred Compensation Earnings represents the net positive increase in actuarial value of the Pension Plan, Pension Restoration Benefit (“PRB”) and Pension Equalization Plans (“PEP”) for the respective years. These benefits have been valued using the assumptions disclosed in Note 17 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2013. Because these assumptions sometimes change between measurement dates, the change in value reflects not only the change in value due to additional benefits earned during the period and the passage of time but also reflects the change in value caused by changes in the underlying actuarial assumptions. The change in pension value was a negative amount for 2013 due to the change in discount rates used to calculate the present value of these benefits from 4.35 percent and 4.25 percent at December 31, 2012, to 5.10 percent and 5.05 percent at December 31, 2013, for the qualified and nonqualified plans, PROXY STATEMENT PROXY respectively. A value of zero is shown in the Summary Compensation Table because the SEC does not allow a negative number to be disclosed in the table.
The Pension Plan and PRB were frozen effective January 1, 2010 for participants who did not satisfy the age 45 and 10 years of service eligibility. Messrs. Cleberg, Evans and Helmers did not meet the eligibility choice criteria and their Defined Pension and PRB benefits were frozen. Mr. Myers did not meet the one-year service requirement prior to the freeze date and, therefore, was never a participant in the Pension Plan.
The PEP is offered through the Grandfathered Pension Equalization Plan (“Grandfathered PEP”), and 2005 Pension Equalization Plan (“2005 PEP”). Messrs. Emery and Helmers are participants in the Grandfathered PEP and 2005 PEP. Messrs. Cleberg, Evans and Myers are not participants in these plans; instead they receive employer contributions into a Nonqualified Deferred Compensation Plan (“NQDC”). The NQDC employer contributions are reported in the All Other Compensation column.
No Named Executive Officer received preferential or above-market earnings on nonqualified deferred compensation. The value attributed to each Named Executive Officer from each plan is shown in the table below.
Defined Total Change in Year Benefit Plan PRB PEP Pension Value David R. Emery 2013 ($24,853) ($21,796) ($78,744) ($125,393) 2012 $91,809 $365,253 $256,432 $713,494 2011 $127,968 $627,383 $508,159 $1,263,510 Anthony S. Cleberg 2013 ($1,474) ($849) $— ($2,323) 2012 $3,952 $2,261 $— $6,213 2011 $6,644 $2,996 $— $9,640 Linden R. Evans 2013 ($16,974) ($15,230) $— ($32,204) 2012 $18,703 $19,207 $— $37,910 2011 $33,608 $25,370 $— $58,978 Steven J. Helmers 2013 ($13,452) ($9,599) $17,301 ($5,750) 2012 $21,518 $16,601 $100,612 $138,731 2011 $37,490 $22,071 $190,248 $249,809 Robert A. Myers 2013 $— $— $— $— 2012 $— $— $— $— 2011 $— $— $— $—
30 30 | PROXY (5) All Other Compensation includes amounts allocated under the 401(k) match, defined contributions, NQDC contributions, dividends received on restricted stock and other personal benefits. Other Personal Benefits column reflects the personal use of a Company vehicle.
Other 401(k) Defined NQDC Dividends on Personal Total Other
Year Match Contribution Contribution Restricted Stock Benefits Compensation PROXY STATEMENT David R. Emery 2013 $15,300 $— $— $38,876 $10,118 $64,294 Anthony S. Cleberg 2013 $15,300 $7,650 $187,280 $16,223 $5,429 $231,882 Linden R. Evans 2013 $15,300 $7,650 $246,831 $31,780 $6,452 $308,013 Steven J. Helmers 2013 $15,300 $8,925 $70,273 $11,233 $6,572 $112,303 Robert A. Myers 2013 $15,300 $7,650 $148,955 $8,985 $11,202 $192,092
GRANTS OF PLAN BASED AWARDS IN 2013(1)
Estimated Future Payouts Estimated Future Payouts Under Non-Equity Incentive Plan Under Equity Incentive Plan All Other Grant Awards(2) Awards(3) Stock Date Awards: Fair Date of Number of Value Comp- Shares of of ensation Stock or Stock Grant Committee Threshold Target Maximum Threshold Target Maximum Units(4) Awards(5) Name Date Action ($) ($) ($) (#) (#) (#) (#) ($) David R. $311,805 $623,610 $1,247,220 Emery 1/30/13 1/30/13 7,218 14,436 28,872 $517,531 2/4/13 1/30/13 12,874 $519,981 Anthony S. $90,725 $181,450 $362,900 Cleberg 1/30/13 1/30/13 2,776 5,552 11,104 $199,039 2/4/13 1/30/13 4,952 $200,011 Linden R. $139,912 $279,825 $559,650 Evans 1/30/13 1/30/13 2,776 5,552 11,104 $199,039 2/4/13 1/30/13 4,952 $200,011 Steven J. $71,505 $143,010 $286,020 Helmers 1/30/13 1/30/13 1,874 3,748 7,496 $134,366 2/4/13 1/30/13 3,342 $134,983 Robert A. $62,740 $125,480 $250,960 Myers 1/30/13 1/30/13 1,527 3,054 6,108 $109,486 2/4/13 1/30/13 2,723 $109,982
(1) No stock options were granted to our Named Executive Officers in 2013.
(2) The columns under “Estimated Future Payouts Under Non-Equity Incentive Plan Awards” show the range of payouts for 2013 performance under our Short-Term Incentive Plan as described in the Compensation Discussion and Analysis under the section titled “Short-Term Incentive” on page 22. If the performance criteria are met, payouts can range from 50 percent of target at the threshold level to 200 percent of target at the maximum level. The 2014 bonus payment for 2013 performance has been made based on achieving the criteria described in the Compensation Discussion and Analysis, at 160 percent of target, and is shown in the Summary Compensation Table on page 29 in the column titled “Non-Equity Incentive Plan Compensation.”
31 PROXY | 31 (3) The columns under “Estimated Future Payouts Under Equity Incentive Plan Awards” show the range of payouts (in shares of stock) for the January 1, 2013 to December 31, 2015 performance period as described in the Compensation Discussion and Analysis under the section titled “Long-Term Incentive – Performance Shares” on page 25. If the performance criteria are met, payouts can range from 50 percent of target to 200 percent of target. If a participant retires, suffers a disability or dies during the performance period, the participant or the participant’s estate is entitled to that portion of the number of performance shares as such participant would have been entitled to had he or she remained employed, prorated for the number of months served. Performance shares are forfeited if employment is terminated for any other reason. During the performance period, dividends and other distributions paid with respect to the shares of common stock accrue for the benefit of the participant and are paid out at the end of the performance period.
(4) The column “All Other Stock Awards” reflects the number of shares of restricted stock granted on February 4, 2013 under our 2005 Omnibus Incentive Plan. The restricted stock vests one-third each year over a three-year period, and automatically vests upon death, disability or a change in control. Unvested restricted stock is forfeited if employment is PROXY STATEMENT PROXY terminated for any other reason. Dividends are paid on the restricted stock and the dividends that were paid in 2013 are included in the column titled “All Other Compensation” in the Summary Compensation Table on page 29.
(5) The column “Grant Date Fair Value of Stock Awards” reflects the grant date fair value of each equity award computed in accordance with the provisions of accounting standards for stock compensation. The grant date fair value for the performance shares was $35.85 per share and was calculated using a Monte Carlo simulation model. Assumptions used in the calculation are included in Note 11 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2013. The grant date fair value for the restricted stock was $40.39 per share for the February 4, 2013 grant, which was the market value of our common stock on the date of grant as reported on the NYSE.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END 2013(1)
Stock Awards Equity Incentive Number Market Value Equity Incentive Plan Awards: of Shares of Plan Awards: Market or Payout or Shares Number of Value of Units or Units Unearned Shares, Unearned Shares, of Stock of Stock Units or Other Units or Other That Have That Have Rights That Have Rights That Have Not Vested(2) Not Vested Not Vested(2) Not Vested Name (#) ($) (#) ($) David R. Emery 25,576 $1,342,996 80,428 $4,195,265 Anthony S. Cleberg 10,673 $560,439 34,179 $1,782,475 Linden R. Evans 20,908 $1,097,879 35,744 $1,862,912 Steven J. Helmers 7,390 $388,049 24,128 $1,257,507 Robert A. Myers 5,911 $310,387 19,035 $992,522
(1) There were no stock options outstanding at December 31, 2013 for our Named Executive Officers.
(2) Vesting dates for restricted stock and performance shares are shown in the table below. The performance shares shown with a vesting date of December 31, 2013, are the actual equivalent shares, including dividend equivalents, earned for the performance period ended December 31, 2013. On January 29, 2014, the Compensation Committee confirmed that the performance criteria were met and there would be a 175 percent payout of target. Performance-to-date results as of December 31, 2013, were above target; therefore, the amounts shown for the performance shares with a vesting date of December 31, 2014 and 2015 reflect a maximum payout level.
32 32 | PROXY Unvested Unvested and Unearned Restricted Stock Performance Shares Name # of Shares Vesting Date # of Shares Vesting Date David R. Emery 4,291 02/04/14 25,032 12/31/13 4,150 02/06/14 13,262 12/31/14 4,402 02/07/14 14,436 12/31/15 PROXY STATEMENT 4,291 02/04/15 4,150 02/06/15 4,292 02/04/16 Anthony S. Cleberg 1,650 02/04/14 10,951 12/31/13 1,897 02/06/14 6,062 12/31/14 1,926 02/07/14 5,552 12/31/15 1,651 02/04/15 1,898 02/06/15 1,651 02/04/16 Linden R. Evans 1,650 02/04/14 12,516 12/31/13 1,897 02/06/14 6,062 12/31/14 2,201 02/07/14 5,552 12/31/15 1,651 02/04/15 1,898 02/06/15 1,651 02/06/16 9,960 02/06/17 Steven J. Helmers 1,114 02/04/14 8,448 12/31/13 1,281 02/06/14 4,092 12/31/14 1,486 02/07/14 3,748 12/31/15 1,114 02/04/15 1,281 02/06/15 1,114 02/04/16 Robert A. Myers 907 02/04/14 6,259 12/31/13 1,043 02/06/14 3,334 12/31/14 1,101 02/07/14 3,054 12/31/15 908 02/04/15 1,044 02/06/15 908 02/04/16
OPTION EXERCISES AND STOCK VESTED DURING 2013(1)
Stock Awards(2) Number of Shares Value Realized on Name Acquired on Vesting (#) Vesting ($) David R. Emery 35,521 $1,340,789 Anthony S. Cleberg 16,666 $628,282 Linden R. Evans 20,365 $765,339 Steven J. Helmers 13,896 $522,122 Robert A. Myers 9,634 $362,897 (1) There were no stock options exercised during 2013. (2) Reflects restricted stock that vested in 2013 and performance shares for the 2010-2012 performance period. The performance share payout was approved by the Compensation Committee on January 30, 2013 and paid out in February 2013. 33 PROXY | 33 PENSION BENEFITS FOR 2013
We made major retirement plan design changes effective January 1, 2010. We adopted a defined contribution plan design as our primary retirement plan and amended our Pension Plan and Nonqualified Pension Plans for all eligible employees to incorporate a partial freeze in which the accrual of benefits ceased for certain participants while other participants were allowed an election to continue to accrue benefits. Employees eligible to elect continued participation were those employees who were at least 45 years old and had at least 10 years of eligible service with us as of January 1, 2010. Mr. Emery is our only Named Executive Officer who met the age and service requirement and continues to accrue benefits under the Pension Plan and the Pension Restoration Plan. Benefits under the Pension Plan and Pension Restoration Plan were frozen for Messrs. Cleberg, Evans and Helmers. Mr. Myers did not meet the one-year service requirement prior to the freeze date and, therefore, was never a participant in the Pension Plan. In addition, Messrs. Emery and Helmers receive supplemental pension benefits under the Grandfathered Pension Equalization Plan, which was frozen effective December 31, 2004, and the 2005 Pension Equalization PROXY STATEMENT PROXY Plan. None of our Named Executive Officers received any pension benefit payments during the fiscal year ended December 31, 2013.
The present value accumulated by each Named Executive Officer from each plan is shown in the table below:
Number of Years of Present Value of Credited Service(1) Accumulated Benefit(2) Name Plan Name (#) ($) David R. Emery Pension Plan 24.33 $563,451 Pension Restoration Benefit 24.33 $2,260,307 Grandfathered Pension Equalization Plan 18.00 $575,901 2005 Pension Equalization Plan 18.00 $1,521,932 Anthony S. Cleberg Pension Plan 1.42 $49,625 Pension Restoration Benefit 1.42 $23,475 Linden R. Evans Pension Plan 8.58 $166,097 Pension Restoration Benefit 8.58 $133,336 Steven J. Helmers Pension Plan 8.92 $233,111 Pension Restoration Benefit 8.92 $144,822 Grandfathered Pension Equalization Plan 11.00 $155,237 2005 Pension Equalization Plan 11.00 $915,331 Robert A. Myers No Benefits
(1) The number of years of credited service represents the number of years used in determining the benefit for each plan. The Pension Equalization Plans are not directly tied to service but rather the number of years of participation in the plan.
(2) The present value of accumulated benefits was calculated assuming the participants will work until retirement, benefits commence at age 62 and using the discount rate, mortality rate and assumed payment form assumptions consistent with those disclosed in Note 17 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2013.
34 34 | PROXY Defined Benefit Pension Plan
Our Pension Plan is a qualified pension plan in which all of our Named Executive Officers except Mr. Myers are included. As discussed above, effective January 1, 2010, we amended our Pension Plan to incorporate a partial freeze in which the accrual of benefits ceased for certain participants while other participants were allowed an election to continue to accrue benefits. Mr. Emery was the only Named Executive Officer who met the age and service requirement and elected to continue with the
existing plan. PROXY STATEMENT
The Pension Plan provides benefits at retirement based on length of employment service and average compensation levels during the highest five consecutive years of the last ten years of service. For purposes of the benefit calculation, earnings include wages and other cash compensation received from us, including any bonus, commission, unused paid time off or incentive compensation. It also includes any elective before-tax contributions made by the employee to a Company sponsored cafeteria plan or 401(k) plan. However, it does not include any expense reimbursements, taxable fringe benefits, moving expenses or moving/relocation allowances, nonqualified deferred compensation, non-cash incentives, stock options and any payments of long-term incentive compensation such as restricted stock or payments under performance share plans. The Internal Revenue Code places maximum limitations on the amount of compensation that may be recognized when determining benefits of qualified pension plans. In 2013, the maximum amount of compensation that could be recognized when determining compensation was $255,000 (called “covered compensation”). Our employees do not contribute to the plan. The amount of the annual contribution by us to the plan is based on an actuarial determination.
The benefit formula for the Named Executive Officers in the Plan is the sum of (a) and (b) below.
(a) Credited Service after January 31, 2000
0.9% of average earnings (up to covered 1.3% of average earnings in excess of covered compensation), multiplied by credited service after Plus compensation, multiplied by credited service after January 31, 2000 minus the number of years of January 31, 2000 minus the number of years of credited service before January 31, 2000 credited service before January 31, 2000
Plus
(b) Credited Service before January 31, 2000
1.2% of average earnings (up to covered 1.6% of average earnings in excess of covered compensation), multiplied by credited service before Plus compensation, multiplied by credited service before January 31, 2000 January 31, 2000
Pension benefits are not reduced for social security benefits. The Internal Revenue Code places maximum limitations on annual benefit amounts that can be paid under qualified pension plans. In 2013, the maximum benefit payable under qualified pension plans was $205,000. Accrued benefits become 100 percent vested after an employee completes five years of service. None of our Named Executive Officers has been credited with extra years of credited service under the plan.
Normal retirement is defined as age 65 under the plan. However, a participant may retire and begin taking unreduced benefits at age 62 with five years of service. Participants who have completed at least five years of credited service can retire and receive defined benefit pension benefits as early as age 55. However, the retirement benefit will be reduced by five percent for each year of retirement before age 62. For example, a participant with at least five years of credited service may retire at age 55 and receive a pension benefit equal to 65 percent of the normal retirement benefit. Mr. Helmers is currently age 57 and is entitled to early retirement benefits under this provision.
A participant who has left employment with us prior to reaching his or her earliest retirement date but who was vested in retirement benefits under the Pension Plan may begin receiving the full value of his or her vested benefit at age 65 or can receive a reduced benefit as early as age 55 if he or she has at least five years of credited service when he or she leaves employment with us. The benefit will be reduced by five percent for each year he or she begins receiving benefits prior to age 65. For example, a participant who leaves employment with us before reaching age 55 with at least five years of credited service may begin receiving benefits at age 55 equal to 50 percent of the normal retirement benefit and may begin receiving retirement benefits at age 65 on an unreduced basis.
If a participant is single, the benefit is paid as a life annuity. If a participant is married, the benefit is paid as a joint and 50 percent survivor annuity unless an optional form of payment is chosen.
35 PROXY | 35 Pension Equalization Plans and Pension Restoration Benefit
We also have a Grandfathered Pension Equalization Plan, a 2005 Pension Equalization Plan and a Pension Restoration Benefit. These are nonqualified supplemental plans, in which benefits are not tax deductible until paid. The plans are designed to provide the higher paid executive employee a retirement benefit which, when added to social security benefits and the pension to be received under the Pension Plan, will approximate retirement benefits being paid by other employers to their employees in similar executive positions. The employee’s pension from the qualified pension plan is limited by the Internal Revenue Code. The 2013 pension limit was set at $205,000 annually and the compensation taken into account in determining contributions and benefits could not exceed $255,000 and could not include nonqualified deferred compensation. The amount of deferred compensation paid under nonqualified plans is not subject to these limits.
As a result of the change in the Pension Plan effective January 1, 2010, the benefits for certain officers (including Messrs. Cleberg, Evans, Helmers and Myers) under the Nonqualified Pension Plans were significantly reduced because the PROXY STATEMENT PROXY nonqualified benefit calculations were linked to the benefits earned in the Pension Plan. As a result, effective January 1, 2010, the Compensation Committee amended the Nonqualified Deferred Compensation Plan to provide non-elective nonqualified restoration benefits to those affected officers who were not eligible to continue accruing benefits under the Pension Plan and Nonqualified Pension Plans.
Grandfathered Pension Equalization Plan and 2005 Pension Equalization Plan. The Grandfathered Pension Equalization Plan provides the pension equalization benefits to each participant who had earned and vested benefits before January 1, 2005, and is not subject to the provisions of Section 409A of the Internal Revenue Code. The 2005 Pension Equalization Plan provides the pension equalization benefits to each participant that were earned and vested on or after January 1, 2005, and is subject to the provisions of Section 409A.
These plans have been frozen to new participants since 2002. A participant under the Grandfathered and 2005 Pension Equalization Plans does not qualify for benefits until the benefits become vested under a defined vesting schedule. A participant is fully vested after eight years of employment under the plan. Messrs. Emery and Helmers are fully vested participants in the Grandfathered and 2005 Pension Equalization Plans. Messrs. Cleberg, Evans and Myers are not participants in these plans.
The annual benefit is 25 percent of the employee’s average earnings, if salary was less than two times the Social Security Wage Base, or 30 percent, if salary was more than two times the Social Security Wage Base, multiplied by the vesting percentage. Average earnings are normally an employee’s average earnings for the five highest consecutive full years of employment during the ten full years of employment immediately preceding the year of calculation. The annual benefit is paid on a monthly basis for 15 years to each participating employee and, if deceased, to the employee’s designated beneficiary or estate, commencing at the earliest of death or when the employee is both retired and 62 years of age or more. A participant with vested benefits who is 55 years of age or older and who is no longer our employee may elect to be paid benefits beginning at age 55 or older, subject to a discount of such benefits according to the following schedule.
Age at Start of Payments % of Benefit Payable Age at Start of Payments % of Benefit Payable 61 93.0% 57 69.7% 60 86.5% 56 64.8% 59 80.5% 55 60.3% 58 74.9%
Pension Restoration Benefit. In the event that at the time of a participant’s retirement, the participant’s salary level exceeds the qualified pension plan annual compensation limitation ($255,000 in 2013) or includes nonqualified deferred compensation, then the participant will receive an additional benefit, called a “Pension Restoration Benefit,” which is measured by the difference between (i) the monthly benefit which would have been provided to the participant under the Pension Plan as if there were no annual compensation limitation and no exclusion on nonqualified deferred compensation, and (ii) the monthly benefit to be provided to the participant under the Pension Plan. The Pension Restoration Benefit applies to all of the Named Executive Officers that have a Pension Benefit.
36 36 | PROXY NONQUALIFIED DEFERRED COMPENSATION FOR 2013
We have a Nonqualified Deferred Compensation Plan for a select group of management or highly compensated employees. Eligibility to participate in the plan is determined by the Compensation Committee and primarily consists of only corporate officers.
A summary of the activity in the plan and the aggregate balance as of December 31, 2013 for our Named Executive Officers is PROXY STATEMENT shown in the following table. Our Named Executive Officers made no personal contributions and received no withdrawals or distributions from the plan in 2013.
Company Aggregate Balance Contributions in Aggregate Earnings at Last Fiscal Name Last Fiscal Year(1) in Last Fiscal Year(2) Year End(3) David R. Emery — — — Anthony S. Cleberg $187,279 $110,976 $706,003 Linden R. Evans $246,831 $93,807 $790,942 Steven J. Helmers $70,273 $23,967 $232,602 Robert A. Myers $148,954 $117,948 $620,519
(1) Our contributions represent non-elective Supplemental Matching and Retirement Contributions and Supplemental Target Contributions (defined in the paragraph below) and are included in the Other Compensation column of the Summary Compensation Table. The value attributed from each contribution type to each Named Executive Officer in 2013 is shown in the table below:
Supplemental Supplemental Supplemental Total Matching Retirement Target Company Contributions Name Contribution Contribution Contribution David R. Emery — — — — Anthony S. Cleberg $25,892 $13,783 $147,604 $187,279 Linden R. Evans $40,517 $20,258 $186,056 $246,831 Steven J. Helmers $19,063 $11,120 $40,090 $70,273 Robert A. Myers $16,932 $8,466 $123,556 $148,954
(2) Because amounts included in this column do not include above-market or preferential earnings, none of these amounts are included in the “Change in Pension Value and Nonqualified Deferred Compensation Earnings” column of the Summary Compensation Table.
(3) Messrs. Cleberg’s, Evans’, Helmers’ and Myers’ aggregate balance at December 31, 2013 includes $461,963, $565,975, $165,929 and $381,292, respectively, which are included in the Summary Compensation Table as 2013, 2012 and 2011, All Other Compensation.
Eligible employees may elect to defer up to 50 percent of their base salary and up to 100 percent of their Short-Term Incentive Plan award, including Company stock, and elect to defer restricted stock grants in the form of restricted stock units. In addition, the Nonqualified Deferred Compensation Plan was amended effective January 1, 2010 to provide certain officers whose Pension Plan benefit and Nonqualified Pension Plans’ benefits were frozen effective January 1, 2010, with non-elective supplemental matching contributions equal to 6 percent of eligible compensation in excess of the Internal Revenue Code limit plus matching contributions, if any, lost under the 401(k) Retirement Savings Plan due to nondiscrimination test results and provides non-elective supplemental age and service points-based contributions that cannot be made to the 401(k) Retirement Savings Plan due to the Internal Revenue Code limit (“Supplemental Matching and Retirement Contributions”). It also provides supplemental target contributions equal to a percentage of compensation that may differ by executive, based on the executive’s current age and length of service with us, as determined by the plans’ actuary (“Supplemental Target Contributions”). Messrs. Cleberg, Evans, Helmers and Myers received Supplemental Target Contributions of 21.5 percent, 20.0 percent, 7.0 percent and 23.0 percent, respectively.
37 PROXY | 37 The deferrals are deposited into hypothetical investment accounts where the participants may direct the investment of the deferrals (except for Company stock and restricted stock unit deferrals) as allowed by the plan. The investment options are the same as those offered to all employees in the 401(k) Retirement Savings Plan except for a fixed rate option, which was set at 2.85 percent in 2013. Investment earnings are credited to the participants’ accounts. Upon retirement, we will distribute the account balance to the participant according to the distribution election filed with the Compensation Committee. The participants may elect either a lump sum payment to be paid within 30 days of retirement (requires a six-month deferral for benefits not vested as of December 31, 2004), or annual or monthly installments over a period of years designated by the participant, but not to exceed 15 years. As of January 1, 2014, Messrs. Cleberg, Evans and Myers are 80 percent vested in the plan and Mr. Helmers is 100 percent vested.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
The following table describes the potential payments and benefits under our compensation and benefit plans and arrangements PROXY STATEMENT PROXY to which our Named Executive Officers would be entitled upon termination of employment. Except for (i) certain terminations following a change in control (“CIC”) of us, as described below, (ii) pro-rata payout of incentive compensation and the acceleration of vesting of equity awards upon retirement, death or disability, and (iii) certain pension and nonqualified deferred compensation arrangements described under Pension Benefits for 2013 and Nonqualified Deferred Compensation for 2013 above, there are no agreements, arrangements or plans that entitle the Named Executive Officers to severance, perquisites, or other enhanced benefits upon termination of their employment. Any agreements to provide other payments or benefits to a terminating executive officer would be in the discretion of the Compensation Committee.
The amounts shown below assume that such termination was effective as of December 31, 2013, and thus include estimates of the amounts that would be paid out to our Named Executive Officers upon their termination. The table does not include amounts such as base salary, short-term incentives and stock awards that the Named Executive Officers earned due to employment through December 31, 2013 and distributions of vested benefits such as those described under Pension Benefits for 2013 and Nonqualified Deferred Compensation for 2013. The table also does not include a value for outplacement services because this would be a de minimis amount. The actual amounts to be paid can only be determined at the time of such Named Executive Officer’s separation from us.
38 38 | PROXY Incremental Continuation Cash Retirement of Medical/ Acceleration Severance Benefit Welfare Benefits of Total Payment (present value)(2) (present value)(3) Equity Awards(4) Benefits David R. Emery • Retirement — — — $1,327,095 $1,327,095
• Death or disability — — — $2,670,091 $2,670,091 PROXY STATEMENT • Involuntary termination — — — — — • CIC — — — $2,813,962 $2,813,962 Involuntary or good reason • (1) termination after CIC $3,936,365 $1,309,600 $123,500 $2,813,962 $8,183,427 Anthony S. Cleberg • Retirement — — — $576,668 $576,668 • Death or disability — — — $1,137,108 $1,137,108 • Involuntary termination — — — — — • CIC — — — $1,195,893 $1,195,893 Involuntary or good reason • (1) termination after CIC $1,088,700 $641,446 $31,800 $1,195,893 $2,957,839 Linden R. Evans • Retirement — — — $576,668 $576,668 • Death or disability — — — $1,674,548 $1,674,548 • Involuntary termination — — — — — • CIC — — — $1,733,333 $1,733,333 Involuntary or good reason • (1) termination after CIC $1,420,650 $762,106 $80,200 $1,733,333 $3,996,289 Steven J. Helmers • Retirement — — — $389,273 $389,273 • Death or disability — — — $777,322 $777,322 • Involuntary termination — — — — — • CIC — — — $817,005 $817,005 Involuntary or good reason • (1) termination after CIC $921,620 $307,099 $29,500 $817,005 $2,075,224 Robert A. Myers • Retirement — — — $317,172 $317,172 • Death or disability — — — $627,559 $627,559 • Involuntary termination — — — — — • CIC — — — $659,893 $659,893 Involuntary or good reason • (1) termination after CIC $878,360 $550,415 $29,500 $659,893 $2,118,168
(1) The amounts reflected for involuntary or good reason termination after a change in control include the benefits a Named Executive Officer would receive in the event of a change in control as a sole event without the involuntary or good reason termination.
(2) Assumes that in the event of a change in control, Mr. Emery will receive an additional three years of credited and vesting service and the other Named Executive Officers will receive an additional two years of credited and vesting service towards the benefit accrual under their applicable retirement plans. For Mr. Emery this would be the Pension Plan and Nonqualified Pension Plans. For Messrs. Cleberg, Evans, Helmers and Myers this would be the Retirement Contributions and Nonqualified Deferred Compensation contributions. The benefits will immediately vest and payments will commence at the earliest eligible date unless the executive has elected a later date for the nonqualified plans. This is age 55 for Messrs. Emery and Evans. Because Messrs. Cleberg, Helmers and Myers are ages 61, 57 and 56, respectively, they are already retiree eligible.
39 PROXY | 39 (3) Welfare benefits include medical coverage, dental coverage, life insurance, short-term disability coverage and long-term disability coverage. The calculation assumes that the Named Executive Officer does not take employment with another employer following termination, elects continued welfare benefits until age 55 or, if later, the end of the two year benefit continuation period (three years for Mr. Emery) and elects retiree medical benefits thereafter. Retirement is assumed to occur at the earliest eligible date.
(4) In the event of retirement, death or disability, the acceleration of equity awards represents the acceleration of unvested restricted stock and the assumed payout of the pro-rata share of the performance shares for the January 1, 2012 to December 31, 2014 and January 1, 2013 to December 31, 2015 performance periods. We assumed a 190 percent payout of the performance shares for the January 1, 2012 to December 31, 2014 performance period and a 162 percent payout of target for the January 1, 2013 to December 31, 2015 performance period based on our Monte Carlo valuations at December 31, 2013. In the event of retirement, all unvested restricted stock is forfeited. PROXY STATEMENT PROXY In the event of a change in control or an involuntary or good reason termination after a change in control, the acceleration of equity awards represents the acceleration of unvested restricted stock and the payout of the pro-rata share of the performance shares calculated as if the performance period ended on December 31, 2013 for the January 1, 2012 to December 31, 2014 and January 1, 2013 to December 31, 2015 performance periods.
The valuation of the restricted stock was based upon the closing price of our common stock on December 31, 2013, and the valuation of the performance shares was based on the average closing price of our common stock for the last 20 trading days of 2013. Actual amounts to be paid out at the time of separation from us may vary significantly based upon the market value of our common stock at that time.
Payments Made Upon Termination. Regardless of the manner in which a Named Executive Officer’s employment terminates, he or his beneficiaries may be entitled to receive amounts earned during his term of employment. These include:
• accrued salary and unused vacation pay; • amounts vested under the Pension Plan and Nonqualified Pension Plans; • amounts vested under the Nonqualified Deferred Compensation Plan; and • amounts vested under the 401(k) Retirement Savings Plan.
Payments Made Upon Retirement. In the event of retirement of a Named Executive Officer, in addition to the items identified above, he will also receive the benefit of the following:
• a pro-rata share of the performance shares for each outstanding performance period upon completion of the performance period; and • a pro-rata share of the actual payout under the Short-Term Incentive Plan upon completion of the incentive period.
Payments Made Upon Death or Disability. In the event of death or disability of a Named Executive Officer, in addition to the items identified above for payments made upon termination, he will also receive the benefit of the following:
• accelerated vesting of restricted stock and restricted stock units; • a pro-rata share of the performance shares for each outstanding performance period upon completion of the performance period; and • a pro-rata share of the actual payout under the Short-Term Incentive Plan upon completion of the incentive period.
Payments Made Upon a Change in Control. Our Named Executive Officers have change in control agreements that terminate November 15, 2016. The renewal of the change in control agreements is at the discretion of the Compensation Committee and the Board of Directors. The change in control agreements provide for certain payments and other benefits to be payable upon a change in control and a subsequent termination of employment, either involuntary or for a good reason. In order to receive any payments under the agreements the Named Executive Officer must sign a waiver which includes a one-year non-competition clause and two-year non-solicitation and non-disparagement clauses.
A change in control is defined in the agreements as:
• an acquisition of 30 percent or more of our common stock, except for certain defined acquisitions, such as acquisition by employee benefit plans, us, any of our subsidiaries, or acquisition by an underwriter holding the securities in connection with a public offering thereof; or
40 40 | PROXY • members of our incumbent Board of Directors cease to constitute at least two-thirds of the members of the Board of Directors, with the incumbent Board of Directors being defined as those individuals consisting of the Board of Directors on the date the agreement was executed and any other directors elected subsequently whose election was approved by the incumbent Board of Directors; or • approval by our shareholders of: - a merger, consolidation, or reorganization;
- liquidation or dissolution; or PROXY STATEMENT - an agreement for sale or other disposition of all or substantially all of our assets, with exceptions for transactions which do not involve an effective change in control of voting securities or Board of Directors membership, and transfers to subsidiaries or sale of subsidiaries; and • all regulatory approvals required to effect a change in control have been obtained and the transaction constituting the change in control has been consummated.
In the change in control agreements, a good reason for termination that triggers payment of benefits includes:
• a material reduction of the executive’s authority, duties or responsibilities; • a reduction in the executive’s annual compensation or any failure to pay the executive any compensation or benefits to which he or she is entitled within seven days of the date due; • any material breach by us of any provisions of the change in control agreement; • requiring the executive to be based outside a 50-mile radius from his or her usual and normal place of work; or • our failure to obtain an agreement, satisfactory to the executive, from any successor company to assume and agree to perform under the change in control agreement.
Upon a change in control, the CEO will have an employment contract for a three-year period and the non-CEO executive will have an employment contract for a two-year period, but not beyond age 65 (“employment term”). During this employment term, the executive will receive annual compensation at least equal to the highest rate in effect at any time during the one-year period preceding the change in control and will also receive employment welfare benefits, pension benefits and supplemental retirement benefits on a basis no less favorable than those received prior to the change in control. Annual compensation is defined to include amounts which are includable in the gross income of the executive for federal income tax purposes, including base salary, targeted short-term incentive, targeted long-term incentive grants and awards; and matching contributions or other benefits payable under the 401(k) Retirement Savings Plan; but exclude restricted stock awards, performance units or stock options that become vested or exercisable pursuant to a change in control.
If a Named Executive Officer’s employment is terminated prior to the end of the employment term by us for cause or disability, by reason of the Named Executive Officer’s death, or by the Named Executive Officer without good reason, the Named Executive Officer will receive all amounts of compensation earned or accrued through the termination date. If the Named Executive Officer’s employment is terminated because of death or disability, the Named Executive Officer or his beneficiaries will also receive a pro rata bonus equal to 100 percent of the target incentive for the portion of the year served.
If the CEO’s employment is terminated during the employment term (other than by reason of death) (i) by us other than for cause or disability, or (ii) by the CEO for a good reason, then the CEO is entitled to the following benefits:
• all accrued compensation and a pro rata bonus (the same as the CEO or the CEO’s beneficiaries would receive in the event of death or disability discussed above); • severance pay equal to 2.99 times the CEO’s severance compensation defined as the CEO’s base salary and short-term incentive target on the date of the change in control; provided that if the CEO has attained the age of 62 on the termination date, the severance payment will be adjusted for the ratio of the number of days remaining to the CEO’s 65th birthday to 1,095 days; • continuation of employee welfare benefits for three years following the termination date unless the CEO becomes covered under the health insurance coverage of a subsequent employer which does not contain any exclusion or limitation with respect to any preexisting condition of the CEO or the CEO’s eligible dependents; • following the three-year period, the CEO may elect to receive coverage under the employee welfare plans of the successor entity at his then-current level of benefits (or reduced coverage at the CEO’s election) by paying the premiums charged to regular full-time employees for such coverage, and is eligible to continue receiving such coverage through the date of his retirement; • three additional years of service and age will be credited to the CEO’s retiree medical savings account and the account balance will become fully vested and he is eligible to use the account balance to offset retiree medical premiums at the later of age 55 or the end of the three year continuation period;
41 PROXY | 41 • three years of additional credited service under the 2005 Pension Equalization Plan, Pension Restoration Plan and Pension Plan; and • outplacement assistance services for up to six months.
If any non-CEO Named Executive Officer’s employment is terminated during the employment term (other than by death) (i) by us other than for cause or disability, or (ii) by the non-CEO for a good reason, then the non-CEO is entitled to the following benefits:
• all accrued compensation and a pro rata bonus (the same as the non-CEO or the non-CEO’s beneficiaries would receive in the event of death or disability discussed above); • severance pay equal to two times the non-CEO’s severance compensation defined as the non-CEO’s base salary and short-term incentive target on the date of the change in control; provided that if the non-CEO has attained the age of 63 on the termination date, the severance payment shall be adjusted for the ratio of the number of days remaining to PROXY STATEMENT PROXY the non-CEO’s 65th birthday to 730 days; • continuation of employee welfare benefits for two years following the termination date unless the non-CEO becomes covered under the health insurance coverage of a subsequent employer which does not contain any exclusion or limitation with respect to any preexisting condition of the non-CEO or the non-CEO’s eligible dependents; • following the two-year period, the non-CEO may elect to receive coverage under the employee welfare plans of the successor entity at his then-current level of benefits (or reduced coverage at the non-CEO’s election) by paying the premiums charged to regular full-time employees for such coverage, and is eligible to continue receiving such coverage through the date of his retirement; • two additional years of service and age will be credited to the non-CEO’s retiree medical savings account and the account balance will become fully vested and the non-CEO is eligible to use the account balance to offset retiree medical premiums at the later of age 55 or the end of the two year continuation period; • two years of additional credited service under the executives’ applicable retirement plans; and • outplacement assistance services for up to six months.
The change in control agreements do not contain a benefit to cover any excise tax imposed by Section 4999 of the Internal Revenue Code of 1986. The executive must sign a waiver and release agreement in order to receive the severance payment.
42 42 | PROXY Proposal 3
ADVISORY VOTE ON OUR EXECUTIVE COMPENSATION
We are providing shareholders with an advisory, non-binding vote on the executive compensation of our Named Executive Officers (commonly referred to as “say on pay”). Accordingly shareholders will vote on approval of the following resolution: PROXY STATEMENT RESOLVED, that the shareholders approve, on an advisory basis, the compensation of our Named Executive Officers as disclosed in the Compensation Discussion and Analysis section, the accompanying compensation tables and the related narrative disclosure in this proxy statement.
This vote is non-binding. The Board of Directors and the Compensation Committee expect to consider the outcome of the vote when considering future executive compensation decisions to the extent they can determine the cause or causes of any significant negative voting results. At our 2013 annual meeting, shareholders owning 94.1 percent of the shares voted approved the foregoing resolution.
As described at length in the Compensation Discussion and Analysis section of this proxy statement, we believe our executive compensation program is reasonable, competitive and strongly focused on pay for performance. The compensation of our Named Executive Officers varies depending upon the achievement of pre-established performance goals, both individual and corporate. Our short-term incentive is tied to earnings per share targets that reward our executives when they deliver targeted financial results. Our long-term incentives are tied to market performance with 50 percent delivered in restricted stock and 50 percent delivered in performance shares. Entitlement to the performance shares is based on our total shareholder return over a three-year performance period compared to our peer group. Through stock ownership guidelines, equity incentives and clawback provisions, we align the interests of our executives with those of our shareholders and our long-term interests. Our executive compensation policies have enabled us to attract and retain talented and experienced senior executives who can drive financial and strategic growth objectives that are intended to enhance shareholder value. We believe that the 2013 compensation of our Named Executive Officers was appropriate and aligned with our 2013 results and position us for long- term growth.
Shareholders are encouraged to read the Compensation Discussion and Analysis, the accompanying compensation tables, and the related narrative disclosures to better understand the compensation of our Named Executive Officers.
The advisory resolution to approve executive compensation is non-binding. However, our Board of Directors will consider shareholders to have approved our executive compensation if the number of votes cast “For” the proposal exceeds the number of votes cast “Against” the proposal. Abstentions and broker non-votes will have no effect on such vote.
The Board of Directors recommends a vote FOR the advisory vote on executive compensation.
43 PROXY | 43 TRANSACTION OF OTHER BUSINESS
Our Board of Directors does not intend to present any business for action by our shareholders at the meeting except the matters referred to in this proxy statement. If any other matters should be properly presented at the meeting, it is the intention of the persons named in the accompanying form of proxy to vote thereon in accordance with the recommendations of our Board of Directors.
SHAREHOLDER PROPOSALS FOR 2015 ANNUAL MEETING
Shareholder proposals intended to be presented at our 2015 annual meeting of shareholders and considered for inclusion in our proxy materials must be received by our Corporate Secretary in writing at our executive offices at 625 Ninth Street, Rapid City, South Dakota 57701, on or prior to November 20, 2014. Any proposal submitted must be in compliance with Rule 14a-8 of PROXY STATEMENT PROXY Regulation 14A of the Securities and Exchange Commission.
Additionally, a shareholder may submit a proposal or director nominee for consideration at our 2015 annual meeting of shareholders, but not for inclusion of the proposal or director nominee in our proxy materials, if the shareholder gives timely written notice of such proposal in accordance with Article I, Section 9 of our Bylaws. In general, Article I, Section 9 provides that, to be timely, a shareholder’s notice must be delivered to our Corporate Secretary in writing not less than 90 days nor more than 120 days prior to the anniversary date of the immediately preceding annual meeting of shareholders.
Our 2014 annual meeting is scheduled for April 29, 2014. Ninety days prior to the first anniversary of this date will be January 29, 2015, and 120 days prior to the first anniversary of this date will be December 30, 2014. For business to be properly requested by the shareholder to be brought before the 2015 annual meeting of shareholders, the shareholder must comply with all of the requirements of Article I, Section 9 of our Bylaws, not just the timeliness requirements set forth above.
SHARED ADDRESS SHAREHOLDERS
In accordance with a notice sent to eligible shareholders who share a single address, we are sending only one annual report and proxy statement to that address unless we receive instructions to the contrary from any shareholder at that address. This practice, known as “householding,” is designed to reduce our printing and postage costs. However, if a shareholder of record residing at such an address wishes to receive a separate annual report or proxy statement in the future, he or she may contact Shareholder Relations at the below address. Eligible shareholders of record receiving multiple copies of our annual report and proxy statement can request householding by contacting us in the same manner. Shareholders who own shares through a bank, broker or other nominee can request householding by contacting the nominee.
We hereby undertake to deliver promptly, upon written or oral request, a separate copy of the annual report to shareholders, or proxy statement, as applicable, to our shareholders at a shared address to which a single copy of the document was delivered.
Shareholder Relations Black Hills Corporation 625 Ninth Street Rapid City, SD 57701 (605) 721-1700
Please vote your shares by telephone, by the Internet or by promptly returning the accompanying form of proxy, whether or not you expect to be present at the annual meeting.
44 44 | PROXY ANNUAL REPORT ON FORM 10-K
A copy of our Annual Report on Form 10-K (excluding exhibits), for the year ended December 31, 2013, which is required to be filed with the Securities and Exchange Commission, will be made available to shareholders to whom this proxy statement is mailed, without charge, upon written or oral request to Shareholder Relations, Black Hills Corporation, 625 Ninth Street, Rapid City, SD 57701, Telephone Number: (605) 721-1700. Our Annual Report on PROXY STATEMENT Form 10-K also may be accessed through our website at www.blackhillscorp.com.
IMPORTANT NOTICE REGARDING THE AVAILABILITY OF PROXY MATERIALS FOR THE SHAREHOLDER MEETING TO BE HELD ON APRIL 29, 2014
Shareholders may view this proxy statement, our form of proxy and our 2013 Annual Report to Shareholders over the Internet by accessing our website at www.blackhillscorp.com. Information on our website does not constitute a part of this proxy statement.
By Order of the Board of Directors,
ROXANN R. BASHAM Vice President – Governance and Corporate Secretary
Dated: March 20, 2014
45
PROXY | 45 Appendix A Reconciliation of Non-GAAP Financial Measures
Year Ended Dec. 31, 2013 2012 2009 EPS EPS EPS EPS from continuing operations (GAAP) $ 2.61 $ 2.01 $ 2.00 Adjustments, after-tax:
Unrealized gain on certain interest rate swaps (0.44) (0.03) (0.94) PROXY STATEMENT PROXY
Impairment of Oil and Gas assets — 0.39 0.72 Gain on sale of Williston Basin assets, net of incentive compensation — (0.37)— Costs associated with payment of Black Hills Wyoming Project Debt Settlement including settlement of interest rate swaps and write-off of deferred financing cost, net of interest savings 0.15 — — Financing costs relating to early repayment of $250 million bonds, net of interest savings(a) 0.13 — —
Credit facility fee write off-Revolving Credit Facility — 0.02 — Make-whole provision payment, $225 million bonds, net of interest savings — 0.07 —
Partial sale of Wygen I to MEAN ——(0.44)
Improved effective tax rate ——(0.10)
Acquisition facility fee and integration expenses — — 0.14
Total adjustments (0.16) 0.08 (0.62) EPS from continuing operations, as adjusted (Non-GAAP) $ 2.45 $ 2.09 $ 1.38
______(a) Financing costs include a make-whole premium, write-off of deferred financing costs and interest expense on the new debt.
• 17 percent growth in earnings per share from continuing operations, as adjusted, from 2012 to 2013 • 15 percent compound annual growth rate in earnings per share from continuing operations, as adjusted, from 2009 to 2013
USE OF NON-GAAP FINANCIAL MEASURE In addition to presenting our earnings information in conformity with Generally Accepted Accounting Principles (GAAP), the company has provided non-GAAP earnings data reflecting adjustments for special items as specified in the GAAP to Non- GAAP adjustment reconciliation table above. Income (loss) from continuing operations, as adjusted, is defined as Income (loss) from continuing operations adjusted for expenses and gains that the company believes do not reflect the company’s core operating performance. The company believes that non-GAAP financial measures are useful to investors because the items excluded are not indicative of the company’s continuing operating results. The company’s management uses these non-GAAP financial measures as an indicator for planning and forecasting future periods. These non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Our presentation of these Non-GAAP financial measures should not be construed as an inference that our future results will be unaffected by other income and expenses that are unusual, non-routine or non-recurring.
46 46 | PROXY FORM 10K 10K | 1 , every Annual Act. Act. Act). ebsite, if any W 46-0458824 (§ 232.405 of this chapter) Smaller reporting company on which registered Name of each exchange IRS Identification Number , a non-accelerated filer or a New York Stock Exchange shares 44,503,454 Outstanding at January 31, 2014 TION , an accelerated filer , as defined in Rule 405 of the Securities Act). TES , including area code s classes of common stock, as of the latest practicable date. A Non-accelerated filer filiates of the Registrant. Form 10-K (605) 721-1700 625 Ninth Street UNITED ST UNITED ge accelerated filer ashington, DC 20549 DC ashington, AND EXCHANGE COMMISSION EXCHANGE AND W No No No s telephone number No No Rapid City, South Dakota 57701 Rapid City, South Dakota s knowledge, in definitive proxy or information statements incorporated by s knowledge, in definitive proxy or information BLACK HILLS CORPORA
Class Registrant’ es es es es es SECURITIES SECURITIES Accelerated filer At June 30, 2013 $2,135,998,459 ence Y Y Y Y Y Securities registered pursuant to Section 12(b) of the Act: Securities registered pursuant April 29, 2014, are incorporated by reference in Part III of this Form 10-K.
Common stock, $1.00 par value December 31, 2013 December s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2014 s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to Act of 1934 during the preceding 12 months
Title of each class
Incorporated in South Dakota Incorporated in South ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 EXCHANGE OR 15(d) OF THE SECURITIES TO SECTION 13 REPORT PURSUANT ANNUAL TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 SECURITIES EXCHANGE 13 OR 15(d) OF THE TO SECTION REPORT PURSUANT TRANSITION ge accelerated filer Common stock of $1.00 par value Lar
Portions of the Registrant’ State the aggregate market value of the voting stock held by non-af Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Indicate by check mark whether the Registrant is a shell company (as defined in Rule Indicate by check mark whether the Registrant is a lar and posted pursuant to Rule 405 of Regulation S-T Interactive Data File required to be submitted shorter period that the Registrant was required to submit and post such files). during the preceding 12 months (or for such amendment to this Form 10-K. reference in Part III of this Form 10-K or any smaller reporting company (as defined in Rule 12b-2 of the Exchange Meeting of Stockholders to be held on Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and Indicate by check mark if disclosure of delinquent will not be contained, to the best of Registrant’ Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Indicate by check mark whether the Registrant Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Indicate by check mark whether the Registrant Securities Exchange Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Indicate by check mark if the Registrant is to such filing requirements for the past 90 days. file such reports), and (2) has been subject 001-31303 Commission File Number Indicate by check mark if the Registrant is a well-known seasoned issuer Indicate by check mark if the Registrant is For the fiscal year ended For the fiscal For the transition period from ______to ______For the transition period Indicate the number of shares outstanding of each of the Registrant’ Documents Incorporated by Refer 2 |10K FORM 10K Part III Part II Part I ITEM 15. ITEM 14. ITEM 13. ITEM 12. ITEM 11. ITEM 10. ITEM 9B. ITEM 9A. ITEM 9. ITEM 8. ITEMS 7.and7A. ITEM 6. ITEM 5. ITEM 4. ITEM 3. ITEM 1B. ITEM 1A. ITEMS 1.and2. FORWARD-LOOKING INFORMATION WEBSITE ACCESSTOREPORTS GLOSSARY OFTERMSANDABBREVIATIONS INDEX TOEXHIBITS SIGNATURES EXHIBITS, FINANCIALSTATEMENTSCHEDULES PRINCIPAL ACCOUNTINGFEESANDSERVICES DIRECTOR INDEPENDENCE CERTAIN RELATIONSHIPSANDRELATEDTRANSACTIONS, AND MANAGEMENT ANDRELATEDSTOCKHOLDERMATTERS SECURITY OWNERSHIPOFCERTAINBENEFICIAL OWNERS AND EXECUTIVE COMPENSATION GOVERNANCE DIRECTORS, EXECUTIVEOFFICERSANDCORPORATE OTHER INFORMATION CONTROLS ANDPROCEDURES ACCOUNTING ANDFINANCIALDISCLOSURE CHANGES INANDDISAGREEMENTSWITHACCOUNTANTSON FINANCIAL STATEMENTSANDSUPPLEMENTARYDATA AND QUALITATIVEDISCLOSURESABOUTMARKETRISK CONDITION ANDRESULTSOFOPERATIONSQUANTITATIVE MANAGEMENT’S DISCUSSIONANDANALYSISOFFINANCIAL SELECTED FINANCIALDATA SECURITIES STOCKHOLDER MATTERSANDISSUERPURCHASESOFEQUITY MARKET FORREGISTRANT’SCOMMONEQUITY,RELATED SPECIALIZED DISCLOSURES LEGAL PROCEEDINGS UNRESOLVED STAFFCOMMENTS RISK FACTORS BUSINESS ANDPROPERTIES T ABLE OF CONTENTS 2 Page 204 203 191 191 191 190 190 189 189 189 189 1 13 69 66 64 64 64 64 51 8 7 6 3 FORM 10K 10K | 3 TIONS ABBREVIA AND AND 3 TERMS TERMS
OF Y GLOSSAR Carbon dioxide Allowance for Funds Used During Construction for Funds Used During Allowance Ltd. of AltaGas LLC, a subsidiary Energy Colorado AltaGas Renewable Income Other Comprehensive Accumulated Aquila, Inc. of five utilities from 2008 acquisition Our July 14, Asset Retirement Obligations Codification Accounting Standards Update as issued by the FASB Accounting Standards Relief Act of 2012 American Taxpayer Cooperative Basin Electric Power Barrel Billion cubic feet equivalent the Company Black Hills Corporation; subsidiary of Black Hills and Production, Inc., a direct, wholly-owned Black Hills Exploration Hills Gas Resources, Inc. and Black Hills Plateau Non-regulated Holdings, includes Black subsidiaries of Black Hills Exploration and Production, Production LLC, direct wholly-owned Inc. wholly-owned subsidiary of Black Hills Black Hills Service Company LLC, a direct, Corporation wholly-owned subsidiary of Black Hills Electric Black Hills Colorado IPP, LLC a direct Generation of Black Hills Utility Holdings, Inc., and its subsidiaries The name used to conduct the business direct, wholly-owned subsidiary of Black Hills Non- Black Hills Electric Generation, LLC, a regulated Holdings a direct, wholly-owned subsidiary of Black Hills Black Hills Non-regulated Holdings, LLC, Corporation subsidiary of Black Hills Corporation Black Hills Power, Inc., a direct, wholly-owned wholly-owned subsidiary of Black Hills Corporation Black Hills Utility Holdings, Inc., a direct, subsidiary of Black Hills Electric Black Hills Wyoming, LLC, a direct, wholly-owned Generation United States Bureau of Land Management British thermal unit Commission United States Commodity Futures Trading independent consulting and engineering firm Cawley, Gillespie & Associates, Inc., an of Black Hills Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary Corporation The Cheyenne Light, Fuel and Power Company Pension Plan Wyo. by Cheyenne Prairie Generating Station currently being constructed in Cheyenne, for this 132 Cheyenne Light and Black Hills Power. Construction is expected to be completed megawatt facility in 2014. of 23 The City of Gillette, Wyoming, affiliate of the JPB. The JPB financed the purchase percent of Wygen III power plant for the City of Gillette. 2 AFUDC AltaGas AOCI Aquila Transaction ARO ASC ASU ATRA Basin Electric Bbl Bcfe BHC BHEP BHSC Black Hills Colorado IPP Black Hills Energy Black Hills Electric Generation Black Hills Non-regulated Holdings Black Hills Power Black Hills Utility Holdings Black Hills Wyoming BLM Btu CFTC CG&A Cheyenne Light Cheyenne Light Pension Plan Cheyenne Prairie City of Gillette CO The following terms and abbreviations appear in the text of this report and have the definitions described below: and have the definitions the text of this report appear in terms and abbreviations The following 4 |10K FORM 10K GHG GCA GADS GAAP Fitch FERC FDIC FASB EWG Equity ForwardAgreement EPA RegionVIII EPA Enserco Economy Energy ECA EBITDA Dth DSM Dodd-Frank swaps De-designated interestrate DC DART CVA CT CPUC CPCN Cooling DegreeDay Colorado Gas Colorado Electric Greenhouse gases certain servicesthroughtocustomers. Gas CostAdjustment--adjustmentsthatallowustopassthe prudently-incurredcostofgasand Generation AvailabilityDataSystem Accounting principlesgenerallyacceptedintheUnitedStates ofAmerica Fitch Ratings United StatesFederalEnergyRegulatoryCommission Federal DepositoryInsuranceCorporation Financial AccountingStandardsBoard Exempt WholesaleGenerator million sharesofBlackHillsCorporationcommonstock,includingtheover-allotment Equity ForwardAgreementwithJ.P.Morganconnectedtoapublicofferingof4,413,519 Dakota, SouthUtah,Wyomingand27TribalNations EPA RegionVIII(MountainsandPlains)locatedinDenverservingColorado,Montana,North United StatesEnvironmentalProtectionAgency Form 10-K Holdings, whichispresentedindiscontinuedoperationsthroughoutthisAnnualReportfiledon Enserco EnergyInc.,aformerlywholly-ownedsubsidiaryofBlackHillsNon-regulated would havecostmoretoproduceontheutility’sownsystem Electricity purchasedbyoneutilityfromanothertotaketheplaceofelectricitythat and purchasedenergythroughtocustomers. Energy CostAdjustment--adjustmentsthatallowustopasstheprudently-incurredcostoffuel Earnings beforeinterest,taxes,depreciationandamortization,anon-GAAPmeasurement Dekatherms Demand SideManagement Dodd-Frank WallStreetReformandConsumerProtectionAct December 2008.TheseswapsweresettledinNovember2013 flow hedgesundertheaccountingforderivativesandbutsubsequentlyde-designatedin The $250millionnotionalamountinterestrateswapsthatwereoriginallydesignatedascash Direct current during theyearcovered) or restrictionsmultipliedby200,000thendividedtotalhoursworkedforallemployees Days AwayRestrictedTransferred(numberofcaseswithdaysawayfromworkorjobtransfer Credit ValuationAdjustment Combustion turbine Colorado PublicUtilitiesCommission Certificate ofPublicConvenienceandNecessity locations overa30yearaverage. another. NormaldegreedaysarebasedontheNationalWeatherServicedataforselected warmth ofweatherandtocomparerelativetemperaturesbetweenonegeographicarea cooling degreedays.Coolingdaysareusedintheutilityindustrytomeasurerelative temperature foradayisabove65degrees.Thewarmertheclimate,greaternumberof A coolingdegreedayisequivalenttoeachthattheaverageofhighandlow indirect, wholly-ownedsubsidiaryofBlackHillsUtilityHoldings Black HillsColoradoGasUtilityCompany,LP(doingbusinessasEnergy),an indirect, wholly-ownedsubsidiaryofBlackHillsUtilityHoldings Black HillsColoradoElectricUtilityCompany,LP(doingbusinessasEnergy),an 4 FORM 10K 10K | 5 5 Settlement with a utilities commission where the dollar figure is agreed upon, but the specific but the agreed upon, figure is the dollar where commission a utilities with Settlement in public rate orders are not specified to arrive at the figure used by each party adjustments Generation Services owned by Duke Energy Wind Farm, LLC, Happy Jack the high and the low that the average of to each degree degree day is equivalent A heating of the greater the number colder the climate, 65 degrees. The for a day is below temperatures relative to measure the in the utility industry degree days are used days. Heating heating degree between one geographic area and and to compare relative temperatures coldness of weather Service data for selected days are based on the National Weather another. Normal degree year average. locations over a 30 Generation, sold Jan. 18, 2011 owned 50 percent by Black Hills Electric Partnership investment and Electronics Engineers Institute of Electrical Reporting Standards International Financial as Black Hills Energy), a direct, Utility Company, LLC (doing business Black Hills Iowa Gas of Black Hills Utility Holdings wholly-owned subsidiary producer Independent power of seven of our IPP plants The July 11, 2008 sale United States Internal Revenue Service Iowa Utilities Board Electric Power System Joint Powers Board. The JPB Consolidated Wyoming Municipalities financing the electrical system of the City of exists for the purpose of, among other things, Gillette LLC (doing business as Black Hills Energy), a direct, Black Hills Kansas Gas Utility Company, Utility Holdings wholly-owned subsidiary of Black Hills Kilovolt London Interbank Offered Rate Lease Operating Expense transmission system Part of the Western Area Power Association Maximum Achievable Control Technology Mid-Continent Area Power Pool the United States EPA National Emissions Utility Mercury and Air Toxics Rules under from Coal and Oil Fired Electric Utility Steam Standards for Hazardous Air Pollutants Generating Units Thousand barrels of oil Thousand cubic feet Thousand cubic feet equivalent Group, Inc. Montana Dakota Utilities Co., a regulated utility division of MDU Resources Municipal Energy Agency of Nebraska Manufactured Gas Plants Million British thermal units Million cubic feet Million cubic feet equivalent Moody’s Investors Service, Inc. Mine Safety and Health Administration Montana Public Service Commission Megawatts Megawatt-hours Not Applicable Energy required to serve customers within our service territory Energy), a Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills direct, wholly-owned subsidiary of Black Hills Utility Holdings North American Electric Reliability Corporation Happy Jack Day Heating Degree Idaho generating facilities IEEE IFRS Iowa Gas IPP IPP Transaction IRS IUB JPB Kansas Gas kV LIBOR LOE Loveland Area Project MACT MAPP MATS Mbbl Mcf Mcfe MDU MEAN MGP MMBtu MMcf MMcfe Moody’s MSHA MTPSC MW MWh NA Native load Nebraska Gas NERC Global Settlement Global 6 |10K FORM 10K contained onourwebsiteisnot partofthisdocument. Of our websitealongwithCode ofBusinessConduct,CodeEthicsforourChiefExecutive Of practicable aftertheyarefiled. Inaddition,thechartersofour The reportswefilewiththeSEC areavailablefreeofchar NO WRDC WPSC WECC WDEQ VEBA TCIR TCA System PeakDemand Spinning Reserve S&P SO Silver Sage SEC SDPUC SAIDI RMSA Revolving CreditFacility REPA RCRA PUHCA 2005 PUD PSCo PPACA PPA OSHA OCI NYMEX NPSC NPDES NOL NOAA ClimateNormals NOAA NGL ficers, CorporateGovernance GuidelinesoftheBoardDirectorsandPolicyforDirector Independence. 2 x regulated Holdings Wyodak ResourcesDevelopmentCorp.,adirect,wholly-owned subsidiaryofBlackHillsNon- Wyoming PublicServiceCommission Western ElectricityCoordinatingCouncil Wyoming DepartmentofEnvironmentalQuality Voluntary EmployeeBenefitAssociation during aone-yearperiod) Total CaseIncidentRate(averagenumberofwork-relatedinjuriesincurredby100workers transmission coststhatarehigherorlowerthantheapprovedinratecase. Transmission CostAdjustment--adjustmentspassedthroughtothecustomerbasedon system peaksincludedemandloadsfor100percentofplantsregardlessjointownership. Represents thehighestpointofcustomerusageforasinglehoursystemintotal.Our compensate forgenerationortransmissionoutages. Generation capacitythatison-linebutunloadedandcanrespondwithin10minutesto Standard &Poor’s,adivisionofTheMcGraw-HillCompanies,Inc. Sulfur dioxide Silver SageWindpower,LLC,ownedbyDukeEnergyGenerationServices U. S.SecuritiesandExchangeCommission South DakotaPublicUtilitiesCommission System AverageInterruptionDurationIndex Retirement MedicalSavingsAccount corporate purposes,whichmaturesin2017 Our $500millioncreditfacilityusedtofundworkingcapitalneeds,lettersofandother Renewable EnergyPurchaseAgreement Resource ConservationandRecoveryAct Public UtilityHoldingCompanyActof2005 Proved undevelopedreserves Public ServiceCompanyofColorado Patient ProtectionandAffordableCareActof2010 Power PurchaseAgreement Occupational Safety&HealthAdministration Other ComprehensiveIncome New YorkMercantileExchange Nebraska PublicServiceCommission National PollutantDischargeEliminationSystem Net operatingloss Nitrogen oxide NOAA growing degreedayscalculatedfromobservationsatapproximately9,800stationsoperatedby of temperature,precipitation,snowfall,heatingandcoolingdegreedays,frost/freezedates, This datasetisproducedonceevery10years. National OceanicandAtmosphericAdministration Natural GasLiquids(7Gallonsequals1Mcfe) ’ s National W W eather Service. ebsite ge atourwebsitewww Access toReports Audit, GovernanceandCompensation Committeesarelocatedon 6 This datasetcontainsdailyandmonthlynormals .blackhillscorp.com assoon reasonably ficer andSeniorFinance The information FORM 10K 10K | 7 fer fect of each s expectations, fer materially Analysis of Analysis of s Discussion & s Discussion s examination of historical operating trends, s examination of historical All forward-looking statements, whether written or oral and All forward-looking statements, whether , or combination of factors, may cause actual results to dif , or combination of factors, may cause 7 - Risk Factors. Forward-Looking Information Forward-Looking , are expressly qualified by the risk factors and cautionary statements in this , are expressly qualified by the risk factors s expectations, beliefs and projections are expressed in good faith and are believed by the and projections are expressed in good s expectations, beliefs s records and other data available from third parties. Nonetheless, the Company’ data available from third parties. Nonetheless, s records and other s business or the extent to which any factor The Company’ ge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the ef ge from time to time, and it is not possible Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to dif which could cause actual results or outcomes involve risks and uncertainties, Forward-looking statements Financial Condition and Results of Operations. Financial Condition from those expressed. management’ reasonable basis, including without limitation, Company to have a Company’ data contained in the Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the speaks only as of the date on which the statement contained in this document Any forward-looking events or circumstances statement or statements to reflect no obligation to update any forward-looking Company undertakes events. New factors to reflect the occurrence of unanticipated date on which the statement is made or that occur after the emer beliefs or projections may not be achieved or accomplished. beliefs or projections forward-looking statement. materially from those contained in any whether made by or on behalf of the Company within Item 1A Form 10-K, including statements contained This Form 10-K contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements statements are all statements Forward-looking by the SEC. as defined statements forward-looking contains Form 10-K This the words are identified by those statements that without limitation fact, including statements of historical other than concerning and include statements and similar expressions, “plans,” “predicts” “intends,” “estimates,” “expects,” “anticipates,” that are and other statements underlying assumptions or performance, and future events goals, strategies, plans, objectives, forward- otherwise make available may publish or to time, the Company facts. From time statements of historical other than Item 7 - Management’ contained within including statements of this nature, looking statements factor on the Company’ The information ficer and Senior Finance .blackhillscorp.com as soon as reasonably This dataset contains daily and monthly normals monthly normals contains daily and This dataset 6 Audit, Governance and Compensation Committees are located on Access to Reports ge at our website www ebsite eather Service. W W s National s National ’ Standard & Poor’s, a division of The McGraw-Hill Companies, Inc. Standard & Poor’s, a division of The McGraw-Hill unloaded and that can respond within 10 minutes to Generation capacity that is on-line but outages. compensate for generation or transmission usage for a single hour for the system in total. Our Represents the highest point of customer 100 percent of plants regardless of joint ownership. system peaks include demand loads for passed through to the customer based on Transmission Cost Adjustment -- adjustments than the costs approved in the rate case. transmission costs that are higher or lower 100 workers Total Case Incident Rate (average number of work-related injuries incurred by during a one-year period) Voluntary Employee Benefit Association Wyoming Department of Environmental Quality Western Electricity Coordinating Council Wyoming Public Service Commission Black Hills Non- Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of regulated Holdings Sulfur dioxide Natural Gas Liquids (7 Gallons equals 1 Mcfe) equals (7 Gallons Gas Liquids Natural Administration and Atmospheric Oceanic National every 10 years. is produced once This dataset and frost/freeze dates, cooling degree days, snowfall, heating and precipitation, of temperature, by 9,800 stations operated at approximately from observations days calculated growing degree NOAA Nitrogen oxide Net operating loss Elimination System National Pollutant Discharge Commission Nebraska Public Service Exchange New York Mercantile Income Other Comprehensive & Health Administration Occupational Safety Power Purchase Agreement Affordable Care Act of 2010 Patient Protection and of Colorado Public Service Company Proved undeveloped reserves 2005 Public Utility Holding Company Act of Resource Conservation and Recovery Act Renewable Energy Purchase Agreement fund working capital needs, letters of credit and other Our $500 million credit facility used to corporate purposes, which matures in 2017 Retirement Medical Savings Account Index System Average Interruption Duration South Dakota Public Utilities Commission U. S. Securities and Exchange Commission Duke Energy Generation Services Silver Sage Windpower, LLC, owned by x 2 ficers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. ficers, Corporate Governance Guidelines of the Board of Directors and Policy S&P Spinning Reserve System Peak Demand TCA TCIR VEBA WDEQ WECC WPSC WRDC NGL NOAA Normals NOAA Climate NOL NPDES NPSC NYMEX OCI OSHA PPA PPACA PSCo PUD PUHCA 2005 RCRA REPA Revolving Credit Facility RMSA SAIDI SDPUC SEC Silver Sage SO NO The reports we file with the SEC are available free of char practicable after they are filed. In addition, the charters of our Chief Executive Of our website along with our Code of Business Conduct, Code of Ethics for our Of contained on our website is not part of this document. 8 |10K FORM 10K in February2012. Discontinued Operationsinthe accompanyingfinancialinformationincludestheresults ofourEner Statements, inthis by referencetoItem8-Financial StatementsandSupplementaryData,particularly Note Financial ConditionandResults ofOperations.Financialinformationregardingourbusiness segmentsisincorporatedherein W Segment FinancialInformation Annual ReportonForm10-Kforfurtherdetails. classified asdiscontinuedoperations.SeeNote Feb. 29,2012,wesoldEnserco,representingourentireEner engaged innaturalgas,crudeoil,coal,powerandenvironmental marketingandtradingintheUnitedStatesCanada.On For morethan15years,priortoFebruary2012,wealsoowned andoperatedEnserco,anener million and naturalgas,primarilyintheRockyMountainregion.OurNon-regulatedEner non-regulated generatingplants.OurOilandGassegmentengagesintheexploration,developmentproductionof crudeoil W primarily toourutilitiesunderlong-termcontracts.OurCoalMiningsegmentproducescoalatminenearGillette, Our PowerGenerationsegmentproduceselectricpowerfromourgeneratingplantsandsellsthecapacity ener ended Dec.31,2013,andhadtotalassetsof 19,998 milesofgasdistributionmainsandservicelines.OurUtilitiesGroupgeneratednetincome electric transmissionanddistributionlines,ourGasUtilitiesown customers inColorado,Nebraska,IowaandKansas.OurElectricUtilitiesown of CheyenneLightinandaroundCheyenne, South Dakota, Our ElectricUtilitiessegmentgenerates,transmitsanddistributeselectricitytoapproximately comprised ofPowerGeneration,CoalMiningandOilGassegments. Group iscomprisedofregulatedElectricUtilitiesandGassegments,ourNon-regulatedEner W through non-regulatedbusinesses. customers intheBlackHillsregionsince1883.In1956,webeganproducing,sellingandmarketingvariousformsofener formed throughthepurchaseandcombinationofseveralexistingelectricutilitiesrelatedassets,somewhichhadserved company “us” or“our”),isagrowth-oriented,vertically-integratedener Black HillsCorporation,aSouthDakotacorporation(togetherwithitssubsidiaries,referredtohereinasthe“Company ITEMS 1 P Non-regulated Energy Utilities Business Group AR e discussourbusinessstrategyandotherprospectiveinformation inItem7-Management’ e operateprincipallyintheUnitedStateswithtwomajorbusinessgroups:UtilitiesandNon-regulatedEner yo., andsellsthecoalprimarilyunderlong-termcontractstoelectricgenerationfacilitiesincludingourownregulated and T I fortheyearended , BlackHillsPowerandLightCompany AND 2. W yoming, ColoradoandMontanaalsodistributesnaturalgastoapproximately Annual ReportonForm10-K. Dec. 31,2013,andhadtotalassetsof BUSINESS AND PROPER $3.3 billion W yo. OurGasUtilitiessegmentservesapproximately 21 intheaccompanyingNotestoConsolidatedFinancialStatements inthis , wasincorporatedandbeganprovidingelectricutilityservicein1941.It History andOrganization TIES atDec.31,2013 gy Marketingsegment,whichresultedinthissegmentbeing gy companyheadquarteredinRapidCity 8 Oil andGas Coal Mining Power Generation Gas Utilities Electric Utilities Financial Segment $0.5 billionat 604 milesofintrastategastransmissionpipelinesand . Dec. 31,2013. 790 megawattsofgenerationand gy Groupgeneratednetincomeof s Discussionand 4 totheConsolidatedFinancial gy marketingbusinessthat 203,500 electriccustomersin 35,500 gasutilitycustomers 538,000 naturalgasutility gy Marketingsegmentsold $85 millionfortheyear , S.D.Ourpredecessor gy Analysis of . OurUtilities 8,599 milesof gy Groupis $18 ,” “we,” gy gy FORM 10K 10K | 9 408 175 297 880 Winter 2011 181 392 452 1,025 Summer yo. Our electric generating yo. Our electric W filiates. 174 284 820 362 Winter 2012 187 400 449 1,036 ech Services primarily serves gas transportation ech Services primarily Summer T ech Services product lines. Service Guard primarily ech Services product filiates. T customers; and also distribute natural gas to and also distribute 203,500 customers; System Peak Demand (in megawatts) yoming), and Colorado Electric (Colorado). Our Electric (Colorado). Our and Colorado Electric yoming), -owned gas infrastructure facilities, typically through one- -owned gas infrastructure facilities, typically oup 192 280 875 403 Winter 2013 Utilities Gr Utilities residential customers through company technicians and third party through company technicians and third 62,000 residential customers 185 381 988 422 Summer , we sell temporarily-available, contractual pipeline capacity and gas contractual pipeline capacity , we sell temporarily-available, Additionally yoming and Montana), Cheyenne Light (W Montana), Cheyenne yoming and W natural gas utility customers of Cheyenne Light in or around Cheyenne, in or around Cheyenne, of Cheyenne Light utility customers 35,500 natural gas 538,000 customers. oup Overview , we sell excess power to other utilities and marketing companies, including our af to other utilities and marketing companies, , we sell excess power e conduct electric utility operations and combination electric and gas utility operations through three subsidiaries: Black Hills through three subsidiaries: utility operations electric and gas and combination electric utility operations e conduct e conduct natural gas utility operations on a state-by-state basis through our Colorado Gas, Nebraska Gas, Iowa Gas and basis through our Colorado Gas, Nebraska utility operations on a state-by-state e conduct natural gas Guard and services through our Service e also provide non-regulated Total Electric Utilities Peak Demands Cheyenne Light Colorado Electric Black Hills Power Utilities generate, transmit and distribute electricity to approximately to approximately distribute electricity transmit and Utilities generate, approximately System peak demands for the Electric Utilities for each of the last three years are listed below: System peak demands for the Electric Utilities Capacity and Demand Electric Utilities Segment W Dakota, Power (South distribution systems. of electricity principally to our own purchase agreements provide for the supply facilities and power Additionally by constructing customer customers throughout our service territory on-going monthly maintenance agreements. time contracts, with a limited number of Business Gr Business commodities to other utilities and marketing companies, including our af utilities and marketing companies, including commodities to other W network to natural gas through our distribution Our Gas Utilities distribute and transport Kansas Gas subsidiaries. approximately W repair services to approximately provides appliance agreements. through on-going monthly service service providers, typically gy gy ,” “we,” $18 gy Group is 8,599 miles of . Our Utilities Analysis of gy , S.D. Our predecessor , S.D. Our $85 million for the year gy Marketing segment sold 538,000 natural gas utility 35,500 gas utility customers 203,500 electric customers in gy marketing business that 4 to the Consolidated Financial s Discussion and gy Group generated net income of 790 megawatts of generation and Dec. 31, 2013. . miles of intrastate gas transmission pipelines and 604 miles of intrastate gas transmission pipelines $0.5 billion at Financial Segment Electric Utilities Gas Utilities Power Generation Coal Mining Oil and Gas 8 gy company headquartered in Rapid City headquartered in gy company gy Marketing segment, which resulted in this segment being at Dec. 31, 2013 TIES History and Organization History and , was incorporated and began providing electric utility service in 1941. It was began providing electric utility service , was incorporated and 21 in the accompanying Notes to Consolidated Financial Statements in this yo. Our Gas Utilities segment serves approximately yo. Our Gas Utilities segment serves approximately W $3.3 billion AND PROPER AND BUSINESS BUSINESS Dec. 31, 2013, and had total assets of Annual Report on Form 10-K. yoming, Colorado and Montana and also distributes natural gas to approximately yoming, Colorado and Montana and also W AND 2. AND , Black Hills Power and Light Company , Black Hills Power for the year ended I T yo., and sells the coal primarily under long-term contracts to electric generation facilities including our own regulated and contracts to electric generation facilities including our own regulated yo., and sells the coal primarily under long-term e operate principally in the United States with two major business groups: Utilities and Non-regulated Ener groups: Utilities and Non-regulated in the United States with two major business e operate principally e discuss our business strategy and other prospective information in Item 7 - Management’ AR Business Group Utilities Non-regulated Energy Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company to herein as the its subsidiaries, referred (together with Dakota corporation Corporation, a South Black Hills ener vertically-integrated is a growth-oriented, “us” or “our”), company some of which had served electric utilities and related assets, purchase and combination of several existing formed through the various forms of ener began producing, selling and marketing Hills region since 1883. In 1956, we customers in the Black businesses. through non-regulated W Ener Gas Utilities segments, and our Non-regulated of regulated Electric Utilities and regulated Group is comprised Gas segments. Generation, Coal Mining and Oil and comprised of Power transmits and distributes electricity to approximately Our Electric Utilities segment generates, South Dakota, of Cheyenne Light in and around Cheyenne, and Kansas. Our Electric Utilities own customers in Colorado, Nebraska, Iowa and our Gas Utilities own electric transmission and distribution lines, lines. Our Utilities Group generated net income of 19,998 miles of gas distribution mains and service ended Dec. 31, 2013, and had total assets of ener electric power from our generating plants and sells the electric capacity and Our Power Generation segment produces contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, primarily to our utilities under long-term W crude oil and Gas segment engages in the exploration, development and production of non-regulated generating plants. Our Oil Mountain region. Our Non-regulated Ener and natural gas, primarily in the Rocky P 1 ITEMS million an ener For more than 15 years, prior to February 2012, we also owned and operated Enserco, trading in the United States and Canada. On engaged in natural gas, crude oil, coal, power and environmental marketing and Feb. 29, 2012, we sold Enserco, representing our entire Ener classified as discontinued operations. See Note Annual Report on Form 10-K for further details. Segment Financial Information W our business segments is incorporated herein Financial Condition and Results of Operations. Financial information regarding Note by reference to Item 8 - Financial Statements and Supplementary Data, and particularly Statements, in this the results of our Ener Discontinued Operations in the accompanying financial information includes in February 2012. 10 |10K FORM 10K (4) (3) (2) (1) ______As ofDec.31,2013,ourElectricUtilities’ Regulated PowerPlants (6) (5) Total MegawattCapacity Colorado Electric Cheyenne Light Black HillsPower Unit Ben French Diesel #1-5 Diesel #1-5 AIP Diesel Pueblo AirportGeneration Busch Ranch Wygen II Ben FrenchCTs#1-4 Ben FrenchDiesel#1-5 Lange CT Neil SimpsonCT Neil SimpsonI Osage W Neil SimpsonII W economical generationalternativeswhenevaluatingcoststoretrofit theseplantstocomplywithenvironmentalstandards,includingEP Operations atOsageweresuspendedOct.1,2010,andBenFrench wassuspendedon This baseloadplantisoperatedbyPacifiCorpandour W supplies allofthefuelforplant. ownership interest,MDUowns25percentandtheCityofGilletteremaining23interest.Our W (55 megawatts). Light andonecombined-cycle,95megawattunitthatwillbejointlyownedbyCheyenne(40megawatts)BlackHillsPowe r Cheyenne Light. Construction ofa132megawattgas-firedpowergenerationfacilityisunderwaytosupportthecustomersBlackHillsPowernd megawatts ofpowerfromthewindfarm. interest inthewindfarmand Busch Ranch Colorado Electric’ rates andcostswillbedeferredasRegulatoryassetsontheaccompanying ConsolidatedBalanceSheets. is estimatedtobeimmaterialatthetimeofretirement,wewould reasonablyexpectanyremainingvaluetoberecoveredthroughfuture regulations. Osage,BenFrenchandNeilSimpsonIwillberetired onorbeforeMarch21,2014. yodak ygen III yodak, a362megawattmine-mouthcoal-firedpowerplant,isowned80percentbyPacifiCorpand20BlackHillsPower ygen III,a1 (4) (3) (2) (4) W 10 megawattmine-mouthcoal-firedpowerplant,isoperatedbyBlackHillsPower (1) W ind Farm,a29megawattwindfarm,isoperatedbyColoradoElectric. ColoradoElectrichasa50percentownership (5) This facilityisexpectedtobecompletedinthefourthquarterof2014. : (4) The facilitywillincludeonesimple-cycle,37megawattcombustionturbinethatbewhollyownedbyCheyenne (1) ind Farm s : : W .N. Clark(42megawatts)andPuebloUnits#5#6(29 wereretiredasofDec.31,2013. (6) AltaGas ownstheremaining50percent.ColoradoElectrichasa 25-year REP Gas/Oil Wind The windfarmbecameoperationalOct.16,2012. T Coal Coal Coal Coal Coal Coal Coal Fuel ownershipinterestsinelectricgenerationplantswereasfollows: Gas Gas Gas Oil Oil Oil Oil ype WRDC coalminesuppliesallofthefuelforplant. Rocky Ford,Colo. Rapid City,S.D. Rapid City,S.D. Rapid City,S.D. Rapid City,S.D. Gillette, Wyo. Gillette, Wyo. Gillette, Wyo. Gillette, Wyo. Gillette, Wyo. Gillette, Wyo. Pueblo, Colo. Pueblo, Colo. Pueblo, Colo. Pueblo, Colo. Osage, Wyo. Location 10 Ownership Interest % 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 50% 20% 52% Aug. 31,2012,duetotheavailabilityofmore While thenetbookvalueoftheseplants . BlackHillsPowerhasa52percent Owned Capacity (MW) 180.0 790.4 14.5 95.0 80.0 40.0 21.8 25.0 34.5 72.4 90.0 57.2 10.0 10.0 10.0 10.0 40.0 A with WRDC coalmine AltaGas fortheir14.5 1977-1979 1948-1952 Installed 2011 2012 2008 2000 1969 1960 1978 1995 2010 1964 1964 2001 1965 2002 Y ear . A
FORM 10K 10K | 11 gy 38% — 38 62 100% 15.89 74.64 16.77 28.80 46.71 405.47 is The 2011 A 2011 $ $ $ $ $ $ yoming provides yoming provides This PP W W gy needs beyond 14.42 52.08 26.70 47.45 16.05 2 280.29 39 61 37% 100% 2012 $ $ $ $ $ $ gy needs for the years ended 2012 -company agreement, includes an option for A 10.89 53.53 29.95 49.20 14.65 233.47 capacity and ener ygen I facility through 2019. 2013 4 The PP 40 60 36% . W 100% $ $ $ $ $ $ s combined-cycle turbines. 2013 ygen I facility Aug. 31, 2014, whereby Black Hills W ; expiring on Dec. 31, 2031, which provides 200 megawatts of expiring on Dec. 31, 2031, which provides 1 1 ind Project; s ownership interest in the gy from its per megawatt adjusted for capital additions and reduced by W gy expiring on Sept. 3, 2028, which provides up to 29.4 megawatts of s output to Black Hills Power; gy based on various timing intervals throughout 2014; yoming’ yoming expiring on yoming expiring on Dec. 31, 2022, whereby Black Hills W W W $2.6 million ind Farm to Cheyenne Light. Under a separate inter W gill expiring on Dec. 31, 2014, whereby Colorado Electric purchases between 25 gill expiring on Dec. 31, 2014, whereby Colorado Electric purchases between with Duke Ener AltaGas expiring on Oct. 16, 2037, which provides up to 14.5 megawatts of wind ener AltaGas expiring on Oct. 16, 2037, which provides up to 14.5 megawatts of wind A , by resource as a percent of the total power supply for our ener , by resource as a percent of the total power with PacifiCorp expiring on Dec. 31, 2023, which provides for the purchase of 50 megawatts with PacifiCorp expiring on Dec. 31, 2023, with Black Hills Colorado IPP with Car with A with Black Hills with Black Hills A A A gy and capacity from its Gillette CT A A s PP ’ s PP s PP s PP generation. Key contracts include: s PP s PP s 20-year PP owned interest in the Busch Ranch power supply annual average cost of fuel utilized to generate electricity and the average price paid for purchased power power for purchased price paid average and the electricity to generate utilized cost of fuel average annual e have executed various agreements to support our Electric Utilities’ e have executed various agreements to W gy from the Happy Jack . AltaGas’ gy and capacity to Colorado Electric from Black Hills Colorado IPP’ gy and capacity to Colorado Electric from Black Hills Power of coal-fired baseload power; Colorado Electric’ ener accounted for as a capital lease on the accompanying Consolidated Financial Statements; accounted for as a capital lease on the accompanying Colorado Electric’ Cheyenne Light’ 40 megawatts of ener megawatts and 50 megawatts of economy ener Cheyenne Light’ Colorado Electric’ from 60 megawatts of unit-contingent capacity and ener Cheyenne Light to purchase Black Hills purchase price related to the option is depreciation over a 35 year life beginning Jan. 1, 2009 (approximately $5 million per year); depreciation over a 35 year life beginning Jan. 1, 2009 (approximately $5 million Cheyenne Light’ wind ener Cheyenne Light sells 50 percent of the facility’ Total Generated Total • • • • • • • Total Average Fuel Cost Total Average Fuel Power Supply Gas, Oil and Wind Purchased Coal Coal Natural Gas Diesel Oil Coal, Gas and Oil Purchased Power - Renewable Sources Purchased Power - Fuel Source (dollars per megawatt-hour) Fuel Source Our Electric Utilities’ Dec. 31 is as follows: our regulated power plants’ The Electric Utilities’ The Electric (excluding contracted capacity) per megawatt-hour for the years ended Dec. 31 is as follows: 31 is as ended Dec. the years for megawatt-hour per capacity) contracted (excluding Purchased Power 12 |10K FORM 10K (1) ______At Dec.31,2013,ourElectricUtilitiesownedtheelectrictransmissionand distributionlinesshownbelow: Electric andPowderRiverEner transmission lines(greaterthan69kV)andlowvoltage(69kV T Power Sales Colorado Electric Cheyenne Light Black HillsPower-JointlyOwned Black HillsPower Utility ransmission andDistribution.ThroughourElectricUtilities,weownelectrictransmissionsystemscomposedofhighvoltage power pricedif excess generation ortomakeeconomicpurchases toserveournativeloadandcontract obligations,andenablesus totakeadvantageof of oursystem.Itaccommodates scheduling transactionsinbothdirectionssimultaneously without havingtoisolateandphysically reconnectloadorgenerationbetweenthetwotransmission grids,thusenhancingthereliability Hills Power'selectricsystemislocated inthe region intheEast. tie, whichis65percentownedby BasinElectric,providestransmissionaccesstoboththe independently-operated transmission gridsservingthewesternUnitedStatesandeasternStates, respectively Black HillsPowerowns35percentofaDCtransmissiontiethat interconnectsthe • • • • • • • capacity andener ener Cheyenne Light’ Neil SimpsonIIand5megawattsofunit-contingentcapacityfrom Black HillsPower W with decreasingcapacitypurchasedoverthetermofagreement. expires in2023. Black HillsPower provide theCityofGilletteitsoperatingcomponentspinningreserves; purchases withreimbursementofcostsbytheCityGillette.Underthisagreement,BlackHillsPowerwillalso Power willprovidetheCityofGillettewithitsfirst23megawattsfromothergenerationfacilitiesorsystem plant. Duringperiodsofreducedproductionat The CityofGilletteownsa23percentownershipinterestin costs byMDU; provide MDUwith25megawattsfromitsothergenerationfacilitiesorsystempurchasesreimbursementof periods ofreducedproductionat MDU ownsa25percentownershipinterestin of CheyenneLight’ Cheyenne LightandBlackHillsPower Cheyenne Lightsells20megawattsofener wind ener Cheyenne Light’ 2022-2023 2020-2021 2018-2019 2014-2017 ygen IIIandNeilSimpsonIIareasfollows: Agreements. gy throughSept.30,2014,andaseparateagreementwherebyCheyenneLightwillreceive40megawattsof ferentials between thetwogrids. gy fromtheSilverSagewindfarmtoCheyenneLight.Underaseparateinter The transfercapacityofthetieis 200megawattsfrom 10 megawatts-5contingentonWygenIIIandNeilSimpsonII; 12 megawatts-6contingentonWygenIIIandNeilSimpsonII 15 megawatts-10contingentonWygenIIIand5NeilSimpsonII 20 megawatts-10contingentonWygenIIIandNeilSimpsonII This contractisunit-contingentbasedontheavailabilityofourNeilSimpsonIIand s agreementwithBasinElectric,wherebyCheyenneLightwillsupply40megawattsofcapacityand s 20-yearPP OurElectricUtilitieshavevariouslong-termpowersalesagreements.Keyagreementsinclude: gy fromBasinElectricthroughSept.30,2014. ’ ’ s PP s agreementtosupplyup20megawattsofener s excessener gy Corporation. A withMEAN,wherebyMEANwillpurchase5megawattsofunit-contingentcapacityfrom (1) A withDukeEner gy W . ygen III,orduringperiodswhen WECC region. ’ s GenerationDispatch gy fromSilverSagetoBlackHillsPower;and W W gy expiringonSept.30,2029,whichprovidesupto30megawattsof ygen III’ ygen III,orduringperiodswhen This transmissiontieallowsusto buyandsellener South Dakota,Wyoming South Dakota,Wyoming South Dakota,Wyoming 12 s netgeneratingcapacityforthelifeofplant.During Colorado orless). W W State Agreement requiresBlackHillsPowertopurchaseall ygen III’ est toEast,and200megawattsfrom Eastto W The unit-contingentcapacityamountsfrom W W gy andcapacitytoMEANunderacontractthat ygen IIIthroughMay2015;and W ygen IIIisof e alsojointlyownhighvoltagelineswithBasin s netgeneratingcapacityforthelifeof estern andEasterntransmissiongrids,whichare , providesadditionalopportunities tosell WECC regioninthe W (in LineMiles) f-line, BlackHillsPowerwill T ygen IIIisof ransmission -company agreement, 1,179 581 W gy intheEasterngrid 25 44 f-line, BlackHills est andtheMAPP . This transmission W (in LineMiles) ygen IIIplants, Distribution W est. Black 3,062 1,246 2,462
— FORM 10K 10K | 13 (b) ear Area 4% 5% 3% yo., to s 17% 58% 37% 33% (1)% s verage W 30-Y A ariance from estern V W 2011 700 431 908 ind Farm. 6,675 1,259 7,579 7,321 5,749 W Actual s system to Sheridan, s system to (b) . ear 47% 63% 47% 47% (12)% (13)% (11)% (13)% verage 30-Y A ariance from V 2012 filiate entity 937 568 yoming are parties to a shared facilities agreement, yoming are parties to 5,629 1,322 1,043 6,206 6,304 4,921 W for the use of Colorado Electric assets. for the use of Colorado Actual 13 (b) ear ygen III generating facility for the life of the plant. ygen III generating facility for the life of 8% 5% 9% 4% 1% W 48% 28% 24% WECC region through 2023. region WECC verage 30-Y A ariance from V 2013 and Colorado Electric are also parties to a facility fee agreement, whereby are also parties to a facility fee agreement, and Colorado Electric ges for the use of assets by the af ges for the use of assets ges the City of Gillette and MDU for administrative services, plant operations and ges the City of Gillette and MDU for administrative 724 520 918 ges Black Hills Colorado IPP ges Black Hills Colorado AltaGas are parties to a shared joint ownership agreement whereby Colorado Electric AltaGas are parties to a shared joint ownership 1,230 6,691 7,582 7,386 5,740 , Cheyenne Light, and Black Hills , Cheyenne Light, and to a shared joint ownership agreement, whereby , the City of Gillette and MDU are parties Actual s existing load, Cheyenne Light has a network transmission agreement with Light has a network transmission s existing load, Cheyenne Climate Normals. Area Project. AltaGas for operations and maintenance for their share of the Busch Ranch AltaGas for operations and maintenance Agreements - ges ) a (a) s Loveland Black Hills Power maintenance for their share of the Colorado Electric and char Black Hills Power IPP Black Hills Colorado Black Hills Power char whereby each entity char whereby each entity Colorado Electric char f. verage is from NOAA A Our Electric Utilities have the following material operating agreements: have the following material operating Agreements. Our Electric Utilities Combined ( Combined Shared Services Jointly Owned Facilities - ear Association’ Black Hills Power Cheyenne Light Colorado Electric Black Hills Power Cheyenne Light Colorado Electric The combined heating degree days are calculated based on a weighted average of total customers by state. The combined heating degree days are calculated based on a weighted average of total 30-Y • • Cooling Degree Days: Heating Degree Days: Degree Days (a) (b) Power Operating ______The following tables summarize information for our Electric Utilities: The following tables summarize information transmission system to wholesale customers in the customers to wholesale system transmission power on PacifiCorp’ access to deliver network transmission Power also has firm Black Hills to the terms of PacifiCorp’ to renew pursuant 2017, with the right with MDU through power sales contract serve our tarif transmission Light’ In order to serve Cheyenne Operating Statistics Black Hills Power has firm point-to-point transmission access to deliver up to 50 megawatts of power on PacifiCorp’ of power up to 50 megawatts deliver access to transmission point-to-point has firm Hills Power Black 14 |10K FORM 10K (b) (a) ______(c) Residential: Revenue -Electric(inthousands) Total Revenue-Electric Other Revenue: Commercial: Industrial: Municipal: Contract Wholesale: Off-system/Power MarketingWholesale: Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Of Generating Station. 2013 includes$0.7millionand2012$2.1inconstruction savingsincentivesfromtheconstructionofPueblo Other revenueprimarilyconsistsoftransmissionrevenue. a result,ColoradoElectrichaddeferred$8.4millioninof f-system salesrevenueduringpartof2010wasdeferreduntilasharing mechanismwasapprovedbytheCPUCinDecember201 Total OtherRevenue Total Off-system/PowerMarketingWholesale Total Residential Total Commercial Total Industrial Total Municipal Subtotal RetailRevenue-Electric Total ContractWholesale-BlackHillsPower (c) (a) (b) f-system revenuewhichwasallrecognizedinDecember201 14 $ $ 2013 195,975 628,045 225,465 526,430 35,778 64,566 26,510 95,631 33,038 87,732 57,444 80,289 46,621 38,037 20,803 27,705 13,106 86,545 18,445 29,580 21,956 4,612 1,916 8,329 1,918 3,421 8,712 $ $ 2012 182,126 595,542 212,307 492,182 32,053 58,523 29,809 91,550 36,797 82,849 55,600 73,858 46,273 37,540 16,105 25,656 13,373 79,301 18,448 31,905 20,290 4,652 2,336 6,003 1,807 3,268 8,365 $ $ 1. 2011 175,759 577,513 201,575 465,867 31,287 59,826 31,027 84,646 13,018 36,263 73,355 55,331 72,889 57,278 33,332 11,629 25,723 12,912 70,684 17,849 34,889 18,105 Airport 2,787 2,449 1,765 3,172 9,371 1. As FORM 10K 10K | 15 — — — 2,342 15,221 17,563 1, 674,518 745,983 268,317 674,518 270,659 1,948,321 7,092,350 1,717,008 1,720,640 4,414,944 2,659,843 1,732,229 2,677,406 2011 — 84,874 33,183 12,433 12,433 587,832 807,659 587,832 319,954 222,647 118,057 1,794,229 7,017,883 1,796,936 1,678,090 4,279,978 2,607,415 1,830,119 2,737,905 2012 — — 33,374 45,765 45,765 688,318 779,677 247,758 688,318 293,523 281,132 1,886,627 6,891,288 1,768,483 1,441,286 4,107,590 2,456,801 1,801,857 2,783,698 2013 15 (b) (a) . otal Purchased T Total Coal - fired Oil Total Natural Gas and Total Wind Total Generated Colorado Electric Colorado Electric Cheyenne Light Cheyenne Cheyenne Light Black Hills Power Black Hills Cheyenne Light Colorado Electric Cheyenne Light Colorado Electric Black Hills Power Black Hills Power Colorado Electric Black Hills Power .N. Clark suspended operations in 2012. Includes wind power of 222,069 megawatt-hours, 199,079 megawatt-hours and 189,255 megawatt-hours in 2013, 2012 and 201 Includes wind power of 222,069 megawatt-hours, 199,079 megawatt-hours and 189,255 W respectively Coal-fired: Natural Gas and Oil: Wind: Total Generated: Total Generated and Purchased Generated - Generated Purchased - Quantities Generated and Purchased (megawatt-hour) Purchased and Generated Quantities ______(b) (a) 16 |10K FORM 10K (a) ______Residential: Quantities (megawatt-hour) Commercial: Total Energy Industrial: Municipal: Contract Wholesale: Off-system Wholesale: Total QuantitySold: Other Uses,LossesorGeneration,net Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Colorado Electric Cheyenne Light Black HillsPower Includes companyuses,linelosses,testener Total Residential Total OtherUses,LossesandGeneration,net Total Commercial Total Industrial Total Municipal Subtotal RetailQuantitySold Total ContractWholesale-BlackHillsPower Total Off-systemWholesale Total QuantitySold (a) : gy andexcessexchangeproduction. 16 2013 1,447,551 1,978,941 6,891,288 1,056,838 4,642,254 1,002,847 2,028,644 1,343,267 3,084,298 1,456,762 6,456,209 619,857 272,490 555,204 151,506 124,728 158,845 703,604 544,636 730,701 435,079 371,102 281,727 404,009 114,732 158,924 219,349 234,566 357,193 34,344 9,848 2012 1,408,655 2,032,142 7,017,883 4,598,080 1,263,457 1,978,137 1,302,074 3,310,854 1,652,949 6,591,065 614,521 261,792 532,342 136,046 197,355 723,216 577,141 731,785 426,818 358,490 224,448 407,301 121,480 990,239 167,044 160,430 229,062 340,036 93,417 35,933 9,631 2011 1,445,179 2,042,200 7,092,350 4,590,800 1,226,548 2,110,923 1,326,849 3,290,553 1,788,005 6,728,325 629,752 264,492 550,935 108,057 162,316 720,060 601,162 720,978 364,025 351,862 172,840 408,337 126,320 933,039 170,382 282,929 278,528 349,520 93,652 34,235 9,827 FORM 10K 10K | 17 3 2 45 68 115 311 243 506 1,060 4,277 68,178 39,681 93,591 28,347 12,864 11,206 54,955 35,159 81,811 201,450 201,447 171,925 2011 3 2 44 61 107 308 240 475 1,023 4,276 68,508 39,956 93,551 28,353 12,857 11,220 55,296 35,438 81,795 202,015 202,012 172,529 2012 3 3 46 61 110 310 232 469 1,011 4,471 69,087 40,486 93,961 28,419 12,888 11,060 55,840 35,780 82,371 203,534 203,531 173,991 2013 17 Total Electric Customers at End of Year Total Contract Wholesale - Black Hills Power Subtotal Retail Customers Total Other Electric Customers Total Industrial Total Commercial Total Residential Black Hills Power Cheyenne Light Colorado Electric Black Hills Power Cheyenne Light Colorado Electric Black Hills Power Cheyenne Light Colorado Electric Black Hills Power Cheyenne Light Colorado Electric Black Hills Power Black Cheyenne Light Colorado Electric Total Customers: Contract Wholesale: Other Electric Customers: Industrial: Commercial: Residential: Customers at End of Year at End Customers 18 |10K FORM 10K operating informationforthenaturalgasdistributionoperationsofCheyenneLight: Included intheElectricUtilitiesisCheyenneLight’ Cheyenne LightNaturalGasDistribution Gas CustomersatYear-End Quantities Sold(Dth): Gross Margin-Gas(inthousands): Revenue -Gas(inthousands): Industrial Commercial Residential Other GrossMargin Industrial Commercial Residential Other SalesRevenue Industrial Commercial Residential Total QuantitiesSold Total GrossMargin-Gas Total Revenue-Gas s naturalgasdistributionsystem. 18 $ $ $ $ 2013 5,034,357 1,653,021 2,728,797 652,539 35,494 18,178 12,706 37,263 23,047 10,326 The followingtablesummarizescertain 3,993 3,050 881 598 840 $ $ $ $ 2012 4,261,788 1,447,522 2,215,858 598,408 35,021 14,992 10,712 31,424 19,327 2,963 2,715 8,613 766 551 769 $ $ $ $ 2011 4,813,607 1,538,616 2,585,056 689,935 34,807 14,820 10,426 36,818 22,044 10,264 3,345 3,597 545 504 913 FORM 10K 10K | 19 917 3,509 2,433 1,306 8,165 verage A (c) (4)% (1)% (7)% (1)% (3)% ear ariance From V 2011 30-Y Service Lines Gas Distribution Gas Distribution 7,013 6,190 5,991 4,954 6,455 Actual 3,011 3,468 2,653 2,701 11,833 verage A (c) Mains (10)% (15)% (18)% (15)% (13)% ear ariance From Gas Distribution V 2012 30-Y 44 6,093 5,198 5,186 4,190 5,518 126 170 264 604 Actual 19 verage A (c) 8% 1% 8% 9% 14% Intrastate Gas Intrastate ear ariance From ransmission Pipelines ransmission V T 2013 30-Y 7,743 6,516 6,310 5,294 6,922 Actual climate normals. (b) verage is from NOAA A (a) Total ear gins. Combined The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to The combined heating degree days are calculated its weather normalization mechanism. 30-Y Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross mechanism within its rate structure, which minimizes weather impact on gross Kansas Gas has an approved weather normalization mar Kansas Iowa Nebraska Colorado Heating Degree Days: Dec. 31, 2013 Colorado Nebraska Iowa Kansas System Infrastructure (in line miles) as of (in line System Infrastructure ______(b) (c) (a) Degree Days The following tables summarize certain operating information on our Gas Utilities. information on our certain operating tables summarize The following Gas Utilities Segment Gas Utilities 20 |10K FORM 10K Operating Statistics Residential: Revenue (inthousands) Commercial: Industrial: Other: Distribution: Transportation: Total RegulatedRevenue Non-regulated Services Total Revenue Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Total Residential Total Commercial Total Industrial Total OtherSalesRevenue Total Distribution Total Transportation 20 $ $ 2013 122,197 341,492 116,639 107,020 149,971 162,552 484,998 510,255 539,689 67,501 98,498 53,296 21,440 47,494 37,190 10,515 15,753 21,750 65,455 12,943 25,257 29,434 3,436 1,661 2,326 2,265 5,117 6,472 4,809 1,033 900 543 (17) $ $ 2012 284,510 122,129 132,175 403,923 425,268 454,081 55,096 82,669 98,339 48,406 15,677 36,550 30,894 13,614 92,679 18,911 89,511 60,108 10,589 21,345 28,813 9,558 2,458 1,963 5,124 2,066 7,823 5,762 4,128 876 452 181 866 $ $ 2011 106,292 125,493 355,072 119,372 108,149 155,542 168,983 505,107 526,972 554,584 65,185 58,102 20,362 46,179 40,659 12,172 19,571 25,015 72,433 11,175 21,865 27,612 2,521 2,063 3,031 1,971 5,648 5,909 3,935 860 550 846 96 FORM 10K 10K | 21 96 450 217 288 549 846 2,960 6,603 2,373 3,328 1,971 2,455 5,071 3,935 5,909 17,711 51,640 47,491 29,701 11,643 11,702 32,908 21,217 65,471 60,030 41,132 11,175 21,865 22,063 76,646 63,965 47,041 12,908 146,543 187,850 209,715 222,623 2011 $ $ 581 249 257 181 452 866 2,680 6,097 2,362 3,449 2,066 4,787 7,486 4,128 5,762 16,400 46,982 39,561 28,734 10,201 11,071 30,049 19,842 59,498 51,341 41,980 10,589 21,345 20,708 70,087 55,469 47,742 14,726 131,677 172,661 194,006 208,732 2012 $ $ (17) 519 250 321 543 3,009 7,436 2,220 3,310 2,266 1,723 4,515 1,033 4,809 6,472 18,244 53,367 42,961 32,111 11,560 13,060 35,065 21,755 67,443 56,885 43,490 12,943 25,257 22,788 80,386 61,694 49,962 14,396 146,683 189,573 214,830 229,226 2013 $ $ 21 Total Distribution Total Transportation Total Residential Total Commercial Total Industrial Total Other Sales Margins Total Regulated Gross Margin Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Gross Margin (in thousands) Margin (in Gross Residential: Commercial: Industrial: Other: Distribution: Transportation: Total Regulated Gross Margin: Non-regulated Services Total Gross Margin 22 |10K FORM 10K Total DistributionQuantitiesSoldandTransportation: Transportation: Distribution QuantitiesSold: Wholesale andOther: Industrial: Commercial: Distribution QuantitiesSoldandTransportation(inDth) Residential: Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Kansas Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Kansas Iowa Nebraska Colorado Total DistributionQuantitiesSoldandTransportation Total Transportation Total DistributionQuantitiesSold Total WholesaleandOther Total Industrial Total Commercial Total Residential 22 2013 122,919,039 27,971,565 39,240,896 45,809,772 63,821,546 14,457,620 20,176,525 28,171,610 59,097,493 13,513,945 19,064,371 17,638,162 16,201,271 38,220,611 11,359,220 12,717,565 9,896,806 1,015,791 8,881,015 4,559,377 3,355,930 2,867,696 7,056,978 4,770,370 1,506,227 7,174,085 6,969,741 116,234 116,234 648,173 150,227 405,047 2012 107,839,327 26,233,038 32,823,324 40,315,344 60,480,822 14,686,679 18,294,228 26,649,759 47,358,505 11,546,359 14,529,096 13,665,585 12,661,374 29,838,390 8,467,621 7,617,465 4,790,322 3,675,678 2,121,063 5,304,162 3,952,067 1,284,082 5,681,199 8,732,301 9,555,073 5,869,817 850,156 492,633 158,445 463,566 68,419 68,419 2011 114,980,286 28,400,900 35,450,711 42,003,922 59,216,132 15,015,310 18,358,692 24,972,560 55,764,154 13,385,590 17,092,019 17,031,362 15,174,957 35,858,131 10,490,129 12,076,979 9,124,753 8,255,183 4,618,813 3,743,735 2,676,439 6,192,167 4,833,604 1,472,747 6,853,163 6,437,860 869,570 112,253 112,253 409,723 120,779 344,576 FORM 10K 10K | 23 7 7 94 30 209 141 393 3,678 9,453 1,809 1,365 4,128 5,693 1,142 67,496 98,043 15,664 15,398 44,193 71,413 176,386 135,161 477,086 196,319 151,046 528,788 110,010 2011 7 7 94 36 213 136 412 3,681 9,584 1,704 1,261 4,115 5,729 1,166 68,927 98,516 15,626 15,398 44,289 72,857 176,953 135,897 480,293 196,830 151,801 532,022 110,534 2012 7 7 94 36 207 136 421 3,737 9,832 1,795 1,358 4,240 5,868 1,171 70,410 99,315 15,739 15,418 44,726 74,390 178,389 137,525 485,639 198,504 153,458 538,035 111,683 2013 23 Total Residential Total Commercial Total Industrial Total Transportation Total Wholesale Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Colorado Nebraska Iowa Kansas Kansas Colorado Nebraska Iowa Kansas Residential: Customers at End of Year at End Customers Commercial: Industrial: Transportation: Wholesale: Total Customers: Total Customers at End of Year 24 |10K FORM 10K in theirstatestosecurebondsorothersecurities. Certain commissionsalsohavejurisdictionovertheissuanceofdebtorsecurities,andcreationliensonproperty located concerning appropriateratesofreturn,theotherutilities,generaleconomicconditionsandpoliticalenvironment . influenced bymanyfactors,includingthecostofprovidingservice,capitalexpenditures,prudencecostsweincur matters. oversee servicesandfacilities,rateschar Our utilitiesaresubjecttothejurisdictionofpubliccommissionsinstateswheretheyoperate. Curr Rates andRegulation right toprovideelectricener supply distribution network.InColorado,ourelectricutilityissubjecttoruleswhichmayrequirecompetitivebiddingforgenerati on marketers displaceusasthesellerofnaturalgas,westillcollectadistributionchar independent marketersforthesaleofnaturalgastoourindustrialandcommercialcustomers,ininstanceswhere none oftheseinitiativeshavebeenadoptedtodate,withtheexceptionMontana. various restructuringandcompetitiveinitiativeshavebeendiscussedinseveralofthestateswhichourutilitiesoperate,but W Competition fourth quarters. a result,significantamountofnaturalgasrevenueisnormallyrecognizedintheheatingseasonconsistingfirstand and commercialheating,sothedemandforthisproductdependsheavilyuponweatherthroughoutourserviceterritories,as warmer inthewinterandcoolersummer our electricpowersupplyresources,theimpactonoperationsmaynotbeassignificantwhenweatherconditionsare Because ourElectricUtilitieshaveadiversecustomerandrevenuebase,wehistoricallyoptimizedtheutilizationof market price.Inparticular Demand forelectricityandnaturalgasissensitivetoseasonalcooling,heatingindustrialloadrequirements,aswell Our ElectricUtilitiesandGasareseasonalbusinessesweatherpatternsmayimpacttheiroperatingperformance. Seasonal V Utilities Gr e generallyhavelimitedcompetitionfortheretaildistributionofelectricityandnaturalgasinourserviceareas.Inpast, ent Rates . Becauseoftheserules,wefacecompetitionfromotherutilitiesandnon-af The publicutilitycommissionsdeterminetheratesweareallowedtochar ariations ofBusiness oup BusinessCharacteristics , demandisoftengreaterinthesummerandwintermonthsforcoolingheating,respectively gy andcapacityforColoradoElectricwhenresourceplansrequireadditionalresources. ges, accounting,valuationofproperty . Conversely , forourGasUtilities,naturalgasisusedprimarilyresidential 24 filiated independentpowerproducersforthe ge forourutilityservices.Ratedecisionsare , depreciationratesandvariousother ge fortransportingthegasthroughour Although wefacecompetitionfrom The commissions , views . FORM 10K 10K | 25 NA NA NA NA NA NA NA NA NA 65% Power Marketing thereafter deadband , we have 2013; 90% ference Percentage of symmetrical 75% through Activity Shared with Customers 50% subject to The regulatory yoming. W Tariff and Rate Matters Tariff and Rate FERC Transmission Tariff Cost ECA, Energy Efficiency Recovery/DSM, Rate Base Recovery on Acquisition Adjustment GCA, Energy Efficiency Cost Recovery/DSM, Rate Base Recovery of Acquisition Adjustment ECA, TCA, Energy Efficiency Cost Recovery/DSM, Renewable Energy Standard Adjustment GCA, Energy Efficiency Cost Recovery/DSM GCA, Cost of Bad Debt Collected through GCA, Infrastructure System Replacement Cost Recovery Surcharge ECA GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA ECA, TCA, Energy Efficiency Cost Recovery/DSM Environmental Improvement Tariff Cost Recovery Adjustment ECA, TCA GCA, Energy Efficiency Cost Recovery/DSM/Capital Infrastructure Automatic Adjustment Mechanism Date 1983 6/2011 2/2011 2/2009 7/2012 7/2012 1/2012 9/2010 6/2007 6/2013 6/2010 12/2012 Effective (in 25 $43.6 $64.0 $80.9 $27.0 $110.2 $243.5 $405.7 $161.0 $440.2 millions) Rate Base Authorized Global Global Capital Structure 46%/54% 46%/54% 43%/57% 48%/52% 50%/50% 47%/53% 48%/52% Settlement Settlement Debt/Equity 50.9%/49.1% 49.3%/50.7% 8.0% 8.0% 8.5% 9.1% 9.1% 8.4% 8.6% 11.7% 7.93% 8.16% Global Global Return on Rate Base Settlement Settlement Authorized These mechanisms allow the utility operating in that state to collect, or refund, the dif These mechanisms allow the utility operating in that state to collect, or refund, 9.6% 9.6% 9.6% 9.8%- 10.2% 10.8% 10.1% 15.0% 10.5% Equity Global Global Global Rate of Return on Settlement Settlement Settlement Authorized tion Jurisdic- WY WY CO FERC NE KS CO SD MT IA SD WY e produce and/or distribute electricity in four states: Colorado, Montana, South Dakota and e produce and/or distribute electricity in four states: Colorado, Montana, South Subsidiary Cheyenne Light - Electric Cheyenne Light - Gas Colorado Electric Nebraska Gas Kansas Gas Gas Utilities: Colorado Gas Electric Utilities: Black Hills Power Iowa Gas W provisions for recovering the costs to supply electricity vary by state. In all states, subject to thresholds noted below provisions for recovering the costs to supply electricity vary by state. In all states, prudently-incurred cost of fuel and purchased cost adjustment mechanisms for our Electric Utilities that allow us to pass the power through to customers. and the actual cost of the commodities and between the cost of commodities and certain services embedded in our base rates operate also allow the utility operating in certain services without filing a general rate case. Some states in which our utilities or environmental improvements and, in that state to automatically adjust rates periodically for the cost of new transmission new capital investment immediately with these some instances, the utility has the opportunity to earn its authorized return on adjustments. The following table illustrates information about certain enacted regulatory provisions with respect to the states in which the in which the states respect to with provisions regulatory enacted certain about information table illustrates The following operates: Group Utilities 26 |10K FORM 10K to thecustomerbetweenratecases.Someofmechanisms wehaveinplaceincludethefollowing: Light’ W Some ofthemechanismswehaveinplaceincludefollowing: e distributenaturalgasinfivestates:Colorado,Iowa,Nebraska, Kansasand • • • • • • • • • • s naturalgasdistribution,haveGCAsthatallowustopass theprudently-incurredcostofgasandcertainservicesthrough capital infrastructure investments. InNebraska,wehaveanInfrastructure SystemReplacementCostmechanismthatallows forrecoveryofcertain infrastructure investments. In Iowa,wehaveaCapitalInfrastructure GCAs. In KansasandNebraska,weareallowedtorecovertheportion ofuncollectibleaccountsrelatedtogascoststhrough provide formoretimelyrecoverycertaincapitalexpenditures andfluctuationsinpropertytaxes. variability thatoccursfromthelevelusedtoestablishbase ratestobepaidbythecustomer In Kansas,wehaveaweathernormalizationtarif with anannualtrue-upmechanism. from whichwerecoverninemonthsofactualtransmissioninvestmentandthreeforecastedinvestment, and eligibleener provides fornotonlydirectrecovery through 2013. and thesharingof others forthetransmissionofutility'selectricityoverfacilitiesownedbyothers,symmetricalinterest, forecasted increasesordecreasesinpurchasedener In Colorado,wehaveaquarterlyECA component ofBlackHillsPower W went intoef In SouthDakota,wehaveanapprovedannualEnvironmentalImprovementCostRecovery Adjustment isalsoinplace. renewable resourcesandfirmpurchasestothecustomerload.In system powermarketingoperatingincome. system salessharingmechanisminwhichSouthDakotacustomerswillreceiveacreditequalto65percentof increased fuelandpurchasedpowerincurredtoserveSouthDakotacustomers. In SouthDakota,BlackHillsPowerhasanannualadjustmentclausewhichprovidesforthedirectrecoveryof retain 15percent. eliminated andreplacedbyasharingmechanismthatreturned85percenttothecustomerallowedcompany Ef the savingsforcostsbelowthresholdaswell5percentnotcollectedorrefundedabovethreshold. percent oftheincreaseordecreasethatexceeded$1.0millionthreshold,andweabsorbedretained mechanism relatingtotransmissionandtheECA of fuelandpurchasedpowerthroughtoelectriccustomers.UntilJuly1,2012,atCheyenneLight,ourpass-through In that relatesto rate ofreturnduringtheconstructionperiodCheyennePrairieonapproximately60percenttotalprojectcost approved by construction periodonthetotalprojectcostthatrelatestoSouthDakotacustomers. Prairie inlieuoftraditional which allowsforrecoveryofconstructionfinancingcostsfromcustomersduringtheperiodCheyenne In September2013,theSDPUCapprovedaconstructionfinancingriderforBlackHillsPoweref e haveanapprovedFERC fective July1,2012,the$1.0millionthresholdanditsaccompanying95/5percentdistributionmethodologywas W yoming, CheyenneLighthasannualcostadjustmentmechanismsthatallowustopasstheprudently-incurred fect June1,201 WPSC ef W This sharingpercentageincreasesto90percentthecustomersin2014andthereafter yoming customers. gy resources. f-system salesmar fective Nov 1, whichrecoverscostsassociatedwithgenerationplantenvironmentalimprovements. AFUDC. T Additionally ransmission ’ s openaccesstransmissiontarif . 1,2012,whichallowsCheyenneLightandBlackHillsPowertoearncollecta These ridersincreasedgrossmar , butalsofortheissuanceofcreditsdecreasesinpurchasedener The riderallowsBlackHillsPowertoearnandcollectarateofreturnduringthe rider(thewassemi-annualuntil gins, lesscertainoperatingcosts,wherethecustomerreceived75percent Automatic , Coloradoallowsusanannual T The modificationalsoadjuststhemethodologytodirectlyassign arif f basedonaformulaicapproachthatdeterminestherevenue wassubjecttoa$1.0millionthreshold:wecollectedorrefunded95 f thatprovidesapass-throughmechanismforweathermar gy andfuelcosts,includingtherecoveryforamountspayableto Adjustment Mechanismthatallows forrecoveryofcertaincapital 26 W f. yoming asimilarFuelandPurchasedPowerCost gin byapproximately W yoming. T ransmission Cost Aug. 1,2013)thatallowsustorecover Additionally All ofourGasUtilitiesandCheyenne This riderissimilartothe $6.9 million , aswelltarif Adjustment tarif , theECA Adjustment (TCA)rider fective . containsanof The ECA in2013. gy April 1,2013, , fuelcosts, fs that gin f, that
f- f- , FORM 10K 10K | 27 8.8 7.7 0.2 1.4 WPSC The filing pending pending Amount Revenue Approved $ $ $ $ 9.2 0.9 2.8 1.4 13.7 14.1 This adjustment ges (dollars in millions): in ges (dollars Amount Revenue Requested $ $ $ $ $ $ . 25, 2013, the NPSC approved a pending pending 11/2013 4/1/2013 6/16/2013 4/25/2013 Effective Date Effective April 15, 2013, the IUB approved a Capital April 15, 2013, the This rider is similar to the one approved by the This rider is similar to the one approved Adjustment Mechanism with the IUB in December Adjustment Mechanism ept. 17, 2013, the SDPUC approved the construction ept. 17, 2013, the SDPUC approved the WPSC requesting electric and natural gas revenue WPSC requesting an electric revenue increase of $2.8 f. On April 25, 2013 for $0.2 million. yoming customers. On Jan. 17, 2013, the SDPUC approved a yoming customers. On Jan. 17, 2013, the , to recover investment in Cheyenne Prairie, existing W Date AFUDC. 27 8/2013 12/2012 12/2012 12/2013 01/2014 12/2012 Automatic fective Requested The filing seeks a return on equity of 10.25 percent and a capital structure ge mechanism. In an order dated Nov Gas Gas The rider allows Black Hills Power to earn and collect a rate of return during The rider allows Black Hills Power to earn April 1, 2013, and on S Service Electric Electric Electric Type of Therefore, subsequent filings will vary in size based on eligible infrastructure Therefore, subsequent filings will vary Electric/Gas fective fective June 16, 2013. Advocate that provided for a revenue increase of $1.4 million. Advocate that provided for a revenue increase Adjustment Mechanism ef April 1, 2013. fective Activity Automatic (3) (2) (6) (5) (4) (1) August 2013, Nebraska Gas filed with the NPSC an application requesting authority to establish an Infrastructure August 2013, Nebraska Gas filed with in 2012 for Cheyenne Light and Black Hills Power for in 2012 for Cheyenne Light and Black stipulation with interim rates ef 2012, which reflected a request for recovery of costs since our prior rate case in 2010. On March 15, 2013, the IUB our prior rate case in 2010. On March a request for recovery of costs since 2012, which reflected mechanism and not eligible for recovery through this capital infrastructure investments were determined that certain Iowa Gas filed a revised proposed tarif on March 26, 2013, Infrastructure 40 percent share of the total project cost that relates to South Dakota the construction period on its approximately customers. In System Replacement Cost Recovery Char settlement with the Public increases of $12.8 million and $1.3 million, respectively infrastructure and increased operating costs. of 54 percent equity and 46 percent debt. In January 2014, Black Hills Power filed a rate case with the increasing operating costs. million to recover investment in Cheyenne Prairie, existing infrastructure and equity and 47 percent debt. seeks a return on equity of 10.25 percent and a capital structure of 53 percent financing rider ef In December 2012, Black Hills Power filed a request with the SDPUC to use a construction financing rider during the filed a request with the SDPUC to use a construction financing rider during the In December 2012, Black Hills Power of traditional construction of Cheyenne Prairie in lieu In December 2013, Cheyenne Light filed a rate case with the Iowa Gas filed a request for a Capital Infrastructure Iowa Gas filed a request mechanism requires an annual filing. rate case filings. replacements and the timing of future general filed a rate case with the SDPUC requesting an electric revenue increase of In December 2012, Black Hills Power investment in distribution and transmission lines, generation plant upgrades, $13.7 million, or 9.94 percent, to recover operating costs. On Sept. 17, 2013, the SDPUC approved a rate increase of environmental compliance and increased $8.8 million, or 6.4 percent, ef Black Hills Power Nebraska Gas Iowa Gas Black Hills Power Black Hills Cheyenne Light Black Hills Power (4) (6) (3) (5) (2) (1) Pending Rates and Rate Rates Pending The following summarizes recent activity of certain state and federal rate cases, riders and surchar cases, riders rate and federal certain state activity of recent summarizes The following 28 |10K FORM 10K to FERC’ between publicutilitiesandtheir af record-keeping, andreporting requirementsadministeredbyFERC.FERCalsoplacescertain limitationsontransactions the provisionofFERC-jurisdictionalwholesalepowerand transmissionservices.Publicutilitiesarealsosubjecttoaccounting, FERC’ and thetransmissionofelectricityininterstatecommerce. Pursuant totheFederalPower Federal Power Act andPUHCA subsidiaries, includingsubsidiariesthatarepublicutilities and holdingcompaniesregulatedbyFERCundertheFederalPower Ener Federal Regulation level. potential costsassociatedwithanynewrenewableener recovery ofthecostswepaytobeincompliancewithstandardsorobjectives. Although wewillseektorecoverthesehighercostsinrates,canprovidenoassurancethatbeablesecure full portfolio standardshaveincreased,andmaycontinuetoincreasethepowersupplycostsofourElectricUtilityoperations. renewable ener Absent aspecificrenewableener portfolio standardsorobjectives: customers fromrenewableener encourage ourElectricUtilitiestosource,byacertainfuturedate,minimumpercentageoftheelectricitydelivered Certain stateswhereweconductelectricutilityoperationshaveadoptedrenewableener Other StateRegulations • • • • gy Policy s jurisdictionmustmaintaintarif W ener utilities togenerate,orcausebegenerated,atleast10percentoftheirretailelectricitysupplyfromrenewable South Dakota.hasadoptedarenewableportfolioobjectivethatencourages,butdoesnotmandate meeting therenewablerequirements. Senate Bill164,primarilyduetotheverylownumberofcustomerswehaveinMontanaandrelativelyhighcost of that hadtheef applicable "costcap"includedinthestandards.However petition withtheMTPSCrequestingawaiverofrenewableportfoliostandardsprimarilyduetoexceeding percentage oftheirretailelectricitysalesfromeligiblerenewableresources.InMarch2013,BlackHillsPowerfiled a Montana. In2005,establishedarenewableportfoliostandardthatrequirespublicutilitiestoobtain ener electricity fromrenewableener Colorado Electricsubsidiarywillconductanall-sourcesolicitationtoacquireadditionalelectricitywhichmayinclude including theuseofaforwardridermechanism. encourages theCPUCtoconsiderearlierandtimelycostrecoveryforutilityinvestmentinrenewableresources, these renewableresourceacquisitions(ascomparedtonon-renewableresources)islimited2percent. with one-halfoftheseresourcesbeinglocatedatcustomerfacilities. 30 percentofretailsalesby2020.Oftheseamounts,3mustbegeneratedfromdistributedgenerationsources sources equaling:(i)12percentofretailsalesthrough2014;(ii)20from2015to2019;and(iii) require ourColoradoElectricsubsidiarytogenerate,orcausebegenerated,electricityfromrenewableener (ii) atwopercentretailrateimpactforcompliancewiththeelectricresourcestandards. Colorado. adoptedarenewableener s oversight. yoming gy sourcesby2015. gy standardplanwiththeCPUCforyears2015through2017. Act. gy intoourresourcesupply Act. 2005. . Black HillsCorporationisaholdingcompanywhoseassets consistprimarilyofinvestmentsinour W The FederalPower yoming currentlyhasnorenewableener fect ofexcludingBlackHillsPowerfromallrenewableportfoliostandardrequirementsunderState gy generationfacilities. gy mandateintheterritoriesweserve,ourcurrentstrategyistoprudentlyincorporate filiates. OurpublicElectricUtility subsidiariesprovideFERC-jurisdictionalservicessubject fs andrateschedulesonfilewithFERCthatgoverntherates, terms,andconditionsfor Act givesFERCexclusiverate-makingjurisdictionoverwholesale salesofelectricity gy resources.In2014,ourColoradoElectricsubsidiarywillalsofileitsrenewable , seekingtominimizeassociatedrateincreasesforourutilitycustomers.Mandatory gy standardthathastwocomponents:(i)electricresourcestandardsand gy standardsthathavebeenormaybeproposedatthefederalstate At Dec.31,2013,weweresubjecttothefollowingrenewableener W e arecurrentlyincompliancewiththesestandards.In2014,our gy portfoliostandard. 28 , inMarch2013,theMontanaLegislatureadoptedlegislation The netannualincrementalretailrateimpactfrom W e cannotatthistimereasonablyforecastthe gy portfoliostandardsthatrequireor Act, allpublicutilitiessubjectto The electricresourcestandards The standard gy gy FORM 10K 10K | 29 . As a . All of our facilities that s authority and oversight, s authority and oversight, ge limitations and plan , particulate matter and GHG. 5.7 4.5 5.1 ganization with authority to ganization 15.3 yodak Plant, potentially requiring a , mercury s and NERC’ x otal W T As a condition of their market-based rate of their market-based condition As a , NO (in millions) 2 fs on file with FERC. Our Electric Utilities are FERC. Our Electric fs on file with s regulations. $ $ fect a broad range of our utility activities, and fect a broad range of our utility activities, gency response in connection with hazardous and toxic gency response in connection with hazardous , such regulations are promulgated under the Clean regulates surface water oil pollution through its oil A yoming are authorized by FERC to make wholesale sales of sales make wholesale FERC to by are authorized yoming W 29 , the EP fs on file with FERC. file with fs on 2005. ges through NPDES and stormwater permits. ferent from the amounts estimated. ganization. NERC has promulgated mandatory reliability standards, and promulgated mandatory reliability standards, ganization. NERC has fluent limitation guidelines and standards on June 7, 2013, with an Additionally ganizations that operate under FERC’ ganizations that operate , soil and other pollutants, but excluding plant closures and the cost of new , soil and other pollutants, but excluding and Black Hills Black Hills and These laws and regulations af These rules may have an impact on the , air proposed ef A s authority under PUHCA , among other pollutants, carbon monoxide, SO All of our facilities subject to these regulations have compliant prevention plans in place. All of our facilities subject to these regulations have compliant prevention plans The EP 2015 2016 Total Environmental Expenditure Estimates 2014 gy at market-based rates under tarif rates market-based gy at 2005 gives FERC authority with respect to the books and records of a utility holding company with respect to the books and 2005 gives FERC authority Act authorizes FERC to certify and oversee a national electric reliability or electric reliability and oversee a national FERC to certify Act authorizes The ultimate cost could be significantly dif The ultimate cost could be significantly , each files Electric Quarterly Reports with FERC. Black Hills Power owns and operates FERC-jurisdictional interstate interstate FERC-jurisdictional and operates Power owns Hills Black with FERC. Reports Quarterly files Electric , each 2005. PUHCA ges and protection of surface waters from oil pollution. Generally Act and govern overall water/wastewater dischar , including regulations that cover water onmental Matters ater e are subject to numerous federal, state and local laws and regulations relating to the protection of the environment and the regulations relating to the protection of federal, state and local laws and e are subject to numerous ater Issues W existing and potential water/wastewater Our facilities are subject to a variety of state and federal regulations governing dischar W with dischar are required to have such permits have those permits in place and are in compliance implementation requirements. and, therefore, are subject to substantial Power generating facilities burning fossil fuels emit each of the foregoing pollutants regulation and enforcement oversight by various governmental agencies. estimated implementation date of May 2014. Envir W safety and health of personnel and the public. Based on current regulations, technology and plans, the following table contains our current estimates of capital expenditures and plans, the following table contains our current estimates of capital expenditures Based on current regulations, technology years to comply with current environmental laws and regulations as described expected to be incurred over the next three below relating to the protection of air quality Our generation facilities are subject to federal, state and local laws and regulations . bulk-power system and operators of the all users, owners, applicable to reliability standards and enforce mandatory promulgate NERC as the electric reliability or FERC has certified with regional reliability or NERC, in conjunction and Black Hills Utility subsidiaries, Black Hills Service Company with centralized service company utility holding company to FERC’ Holdings, we are subject air and water quality; (ii) the identification, generation, storage, handling, generally regulate: (i) the protection of labeling, reporting of, and emer transportation, disposal, record-keeping, and (iii) the protection of plant and animal species and minimization of noise materials and wastes, including asbestos; emissions. generation. modification to the methods of handling coal ash. pollution prevention regulations. Air Emissions These laws and regulations cover Our Electric Utilities, Black Hills Colorado IPP Colorado Hills Black Utilities, Our Electric PUHCA electric capacity and ener capacity electric authority under tarif transmission service open access facilities and provides transmission FERC’ their compliance with with respect to routine audit by FERC subject to Power The Federal reliability standards. enforces those mandatory 30 |10K FORM 10K control technology the requisitenumberofallowancesbyreducingSO we currentlyholdsuf W T allowances ontheopenmarket. year data. gives theownerrighttoemitonetonofSO T Clean result inaBest monitoring andreportingrequirementswillbeimplemented. Newprojectsormajormodificationstoexistingwill source ofGHGemissions,asdefinedbyEP This rulewillimpactusintheeventofamajormodification atanexistingfacilityorintheeventweestablishanewmajor On June3,2010,theEP expected tobeincompliancewithMA control technologyandhavemercurymonitorsinplace.NeilSimpsonII, Airport GeneratingStationareallowedtooperateundertheirconstructionpermituntilthe have received T of suchnewprojects. integrate thecostofobtainingrequirednumberallowancesneededforfutureprojectsintoouroverallfinancialanalysis W technologies. compliance. NeilSimpsonII, In 201 filed inaccordancewithregulatoryrequirements. Generating Station The rule isissued,sowecannotbe certainofimpactsfromthisrule. third oftheirgeneratingcapacity basedonathree-yearaverage. Airport GeneratingStationthat iscurrentlyunderpermitreview Electric UtilityGeneratingUnits. On Jan.8,2014,theEP expense andconsiderableriskofobtainingapermitfromthe EP includes thetransferofCheyennePrairieEP 22, 2013FederalRegister air permitsfor 16, 2015,withapathwaydefinedtoapplyforoneyearextensionduecertainverylimitedcircumstances. imposes requirementsformercury from CoalandOilFiredElectricUtilitySteamGeneratingUnits(MA On Feb.16,2012,theEP Act. suspended operationsDec.31,2012,andwasretiredon CPUC issuedanorderapprovingtheclosureof French andNeilSimpsonIonorbeforeMarch21,2014.InconjunctionwiththeColoradoClean October 2010andsuspendedoperationsattheBenFrenchfacilityon compliance deadlineofMarch21,2014.Duetocostsretrofittheseplants,wesuspendedoperationsattheOsageplant in updates onDec.21,2012,whichimposeemissionlimits,fuelrequirementsandmonitoringrequirements. itle IV itle IV itle ygen III,Pueblo yoming adoptedandsubmittedaGHGregulatoryprogram totheEP . T V Allowances maybetraded,soaf At theendofeachyear itle 1, theEP Air oftheClean appliestoseveralofourgenerationfacilities,includingtheNeilSimpsonII,CT oftheClean V Act applicationfor T W W A A itle yoming passedGHGlegislationin2012and2013,enabling thestatetoimplementEP issuedtheIndustrialandCommercialBoilerRegulationsfor vailable Control ygen IIand , useofbankedallowances,andifnecessary Airport GeneratingStation,CheyennePrairieand T V Air itle Air ficient allowancestosatisfy permits,withtheexceptionof A A Act requiresthatallofourgeneratingfacilitiesobtainoperatingpermits. V Act createdanSO re-proposedStandardsofPerformance forGreenhouseGasEmissionsfromNewStationary Sources: A promulgatedtheGHG . applicationwasfiledinSeptember2012,withthepermitexpected2014.Bothapplicationswere publishedintheFederalRegisterNationalEmissionStandardsforHazardous As ofDec.23,2013, W , eachemittingunitmustpossessallowancessuf W ygen IIIwassubmittedinJanuary201 W ygen IIIprovidemercuryemissionlimitsandmonitoringrequirementswithwhichwearein ygen IIand T These standardsmayapplyto theLM6000tobeconstructedbyColoradoElectricatPueblo , acidgases,metalsandotherpollutants. echnology reviewthatcouldresultinmorestringentemission controlpracticesand fected unitsthatexpecttoemitmoreSO TS bythecompliancedeadline,withoutincurringsignificantcosts. 2 A allowancetradingregimeaspartofthefederalacidrainprogram.Each W regulations.Uponrenewalofoperatingpermitsforexisting permittedfacilities, ygen IIIhavebeenutilizedforinternalstudyandreviewofmercuryemission 2 A . W
Certain facilitiesareallocatedallowancesbasedontheirhistoricaloperating T GHGairpermit,tothestateof T yoming hasfulljurisdictionovertheGHGpermittingprogram which ailoring Rule,implementingregulationsofGHGforpermitting purposes. itle IV 2 W emissionsthroughtheuseoflowsulfurfuels,installation“backend” W .N. ClarkfacilitynolaterthanDec.31,2013. ygen IIIandPueblo Dec. 31,2013,inaccordancewiththeColoradoClean atallsuchplantsthrough2043.Forfutureplants,weplantosecure , thepurchaseofallowancesonopenmarket. 30 . A. W As proposed,therulewilllimit simple-cycleturbinestoone- e expectmultiplerevisionsand legalactionsbeforethefinal 1, withthepermitexpectedin2014. W TS), withanef Aug. 31,2012. A, whichtheEP yodak plants. W Airport GeneratingStation. Af ygen II, ficient tocoveritsemissionsforthepreceding fected unitshaveacompliancedeadlineof 2 Area SourcesofHazardous thantheirallocatedallowancesmaypurchase W yoming. fective dateof W W W A ygen IIIandthe e plantopermanentlyretireOsage,Ben ithout purchasingadditionalallowances, approvedandpublishedintheNov T itle This eliminatestheincreasedtime, V All ofourexistingfacilities permitisissuedbythestate. Air CleanJobs April 16,2012. The II,LangeCT A W W W ’ The Pueblo s GHGprogram. ygen IIIandPueblo yodak plantare The rulehasa .N. Clarkfacility Air Pollutants,with Air Pollutants The currentstate Air CleanJobs W Act, the e expectto This rule , Airport W ygen II, April . FORM 10K 10K | 31 The and 2
, SO x x Airport Airport 64 52 43 57 71 63 in 2016. Act, a A (in years) yoming power Age of Plant ygen II. and NO W 2 emissions. W x Areas) visibility As the result of these Air Clean Jobs yodak Power Plant within ilderness VIII, identifying NO ygen I and W Dec. 31, 2013 Dec. 31, 2013 Dec. 31. 2013 W W Among other things, the rule seeks things, the rule Among other March 21, 2014 March 21, 2014 March 21, 2014 Retirement Date Planned or Actual s Stationary Reciprocating Internal s Stationary Reciprocating ’ Region A A s New Source Review regulations, with the Review regulations, s New Source ’ A NA The primary impact is expected to be on our older to be on our older impact is expected The primary yoming Regional Haze Federal Implementation Plan Oct. 1, 2010 Dec. 31, 2012 Dec. 31, 2012 Dec. 31, 2012 Aug. 31, 2012 W This represented a significant change from requirements This represented a significant Date Suspended The unit was previously fitted with state of the art low The unit was previously fitted with state regulations issued in recent years. ygen III for further reductions in NO ygen III for further Although none of our South Dakota or A emission limitations. emission x W Areas (National Parks and e anticipate this ruling will be litigated. Also in 2014, Neil Simpson II will be converting startup fuel Also in 2014, Neil Simpson II will be converting yoming Regional Haze Plan update due to the EP W 31 Gas Gas yoming would be a non-attainment area. Under those conditions, non-attainment area. Under those conditions, yoming would be a Coal Coal Coal Coal Plant W .N. Clark facility on Dec. 31. 2013. Type of W W , ygen II and control upgrades to be completed at the x yoming may require similar changes to yoming may require similar changes to W 9.0 published the final W 25.0 21.8 42.0 20.0 34.5 A 152.3 Megawatts s Regional Haze Program. ’ A Act, we retired the Act was to require utilities to consider a spectrum of regulations when evaluating their Act was to require utilities to consider A's currently proposed Regional Haze Federal Implementation Plan, which includes A's currently proposed Regional Haze Federal Implementation Plan, which includes yoming and South Dakota submitted their plans to EP yoming and South Dakota submitted their Air Pollutant regulations. Evaluations were completed, emission control equipment was Evaluations were completed, emission Air Pollutant regulations. W Company Total MW proposed revisions to the Electric Utility New Source Performance Standards for stationary stationary for Standards Performance Source Utility New Electric to the revisions proposed Colorado Electric Colorado Electric Colorado Electric Black Hills Power Black Hills Power Black Hills Power yoming issued a letter requiring Neil Simpson II to include startup and shutdown SO requiring Neil Simpson II to include yoming issued a letter A , which requires significant NO This rule is expected to be finalized in 2014 and, as proposed, will be applicable to the Pueblo the Pueblo to be applicable will and, as proposed, in 2014 finalized to be rule is expected This As required by the W 1, the states of yoming may evaluate Neil Simpson II, yoming may evaluate W Plant is expected to propose a more stringent ozone ambient air standard in 2014. If the lower range of the proposed standard in 2014. If the lower range of a more stringent ozone ambient air is expected to propose Those changes enabled the unit to meet the new requirements. Those changes enabled the unit to meet A for approval. 1, the State of A burners that support compliance with this new requirement. burners that support compliance with this Ben French Neil Simpson I W.N. Clark Pueblo Unit #5 Pueblo Unit #6 Osage x August 2012, the EP 2012, the August yodak Power Plant is included in EP number of our power plants have been subject to new state and EP number of our power plants have been In addition, Neil Simpson II is expected to be included in the additional NOx controls. On Jan. 30, 2014, the EP W five years. Our share of those costs is estimated at $20 million. The EP installed and emission testing confirmed compliance with those requirements. testing confirmed compliance with installed and emission it is anticipated that Campbell County standard is selected, By May 3, 2013, all our diesel generator engines were required to comply with the EP our diesel generator engines were required By May 3, 2013, all Hazardous Combustion Engine the State of In 201 limits. compliance with permitted emission emissions when evaluating scrubber performance during design changes were made to improve 1993 air permit. Minor engineered provided in the original startup. NO in the Federal Register In combustion turbines. turbines. combustion In January 201 of Colorado passed House Bill 1365, the Colorado Clean In the 2010 legislative session, the State from diesel to natural gas. In the future the State of from diesel to natural gas. In the future Regional Haze intended to meet the Class I particulate matter emission reductions improvement requirements under the EP will be anticipate that in the next required revisions due in 2016, some of our plants plants were included in those plans, we not the Simpson I will be permanently retired on or prior to March 21, 2014. If this was included. Ben French, Osage and Neil with Neil Simpson II, would be included in revised regulations. case, it is highly probable these plants along of retrofit many of our older generating plants, we have announced the suspension regulations and the associated costs to operations and retirements for the following plants: Generating Station, Cheyenne Prairie and eventually all the combustion turbines in our fleet. turbines in our all the combustion Prairie and eventually Station, Cheyenne Generating on the EP overhauls for impact and clearly define startup exemptions to eliminate low from coal fired power plants and promote the use of natural gas and other coordinated utility plan to reduce air emissions emitting resources. One purpose of this submitted package ultimately comprising Colorado's Regional Haze Plan that would be emission reduction plans, with the final to EP A intention of eventually bringing all units under the applicability of this rule. applicability of this all units under the eventually bringing intention of to meet tighter NO be required which will eventually existing units, 32 |10K FORM 10K 2014. As ofOct.1,2010,wesuspendedoperationsattheOsage power plantanditisscheduledtoberetiredonorbeforeMarch21, post-mining groundwaterquality material coststomitigateany resultingdamages. pollute under permitted, privately-ownedlandfill. Our scheduled tocloseonorbeforeMarch21,2014. post closuremonitoringwillcontinuefor30years. September 2013,Osagealsoreceivedapermittoclosethe smallindustrialrubblelandfill.Siteworkhasbeencompletedand on water but thewastedoescontainminutetracesofmetalsthatcould beperceivedaspollutingifsuchmetalsleachedintounder exact requirementsareknown.Noneofthesolidwastefromburningcoaliscurrentlyclassifiedashazardous material, areas thatareabovegroundwateraquifers. In 2009,theStateof mined areasatthe sulfur removalfromtheBenFrench, collected asaresultofburningcoalatourpowerplantsinapprovedsolidwastedisposalsites. V Solid W generating unitsmoreexpensiveoruneconomicaltooperateandmaintain. or cashflows.Inaddition,futurechangesinenvironmentalregulationsgoverningairemissionscouldrendersomeof ourpower including utilityaf generating plantsfromutilitycustomersandotherpurchasersofthepowergeneratedbyournon-regulatedplants, or otherrequirements. generating plantsareincludedinratebase,wewillattempttorecovercostsassociatedwithcomplyingemission standards supply fromrenewableresources,andtheclosureofcertaingeneratingfacilities. expenditures, thepurchaseofadditionalemissionsallowancesor relating to,amongotherthings,theinstallationofadditionalemissioncontrolequipment,accelerationcapital New ormorestringentregulationsotherener develops andlitigationisresolved. outcome ofwhichcouldimpacttheutilityindustry regulations havebeenproposedinvariousstatesandallegedclimatechangeissuesarethesubjectofanumberlawsuits, W our PowerGenerationandGasUtilitiesinordertocomplywiththeEP how thisrequirementwillimpactourexistingfacilitiesuponpermitrenewal.In2013,wereported201 upon renewalof Rule wentintoef impact onourcustomerrates,financialposition,resultsofoperationsand/orcashflows.In201 the regulation,anyfederallymandatedGHGreductionsorlimitsonCO steam electricgeneratingunits. their generatingcapacitybasedonathree-yearaverage. sequestration becomestechnicallyandeconomicallyfeasible.Italsorestrictssimple-cyclenaturalgasturbinestoone-thirdof CO June 2014,whichwillapplytonewsteamelectricgeneratingunits,asdescribedabove. are themostsignificantsourcesofCO sources, andminimalquantitiesofbothsolarhydroelectricpower W Gr arious materialsusedatourfacilitiesaresubjecttodisposalregulations.Understatepermits,wedisposeofallsolid wastes e continuetoreportannualGHGemissionsasrequiredbytheEP e utilizeadiversifiedener eenhouse GasRegulations April 13,2012.Siteclosureworkwascompletedandpost-closure monitoringactivitieswillcontinuefor30years.In 2 emissionsstandards,ef W . This planthasanon-siteashimpoundmentthatisnearcapacity .N. Clarkplant,whichsuspended operationsonDec.31,2012andwasretired W aste Disposal e conductedinvestigationswhichconcludedthatthewastes arerelativelyinsolubleandwillnotmeasurablyaf ground water T fect, requiringGHGemissionstobeaddressedinnewmajorsourceconstructionpermits,and itle filiates. WRDC coalmine. W V W yoming confirmeditspastapprovalofthispracticebutmayre-evaluateandlimitashdisposaltomined OperatingPermits.Sincetherearenoemissionstandardsorcapscurrentlyinplace,wecannotpredict e willalsoattempttorecovertheemissioncompliancecostsofournon-regulatedfossil-fuel , wecanprovidenoassurance thatpollutionwillnotoccurovertime.Inthisevent,we could incur Any unrecoveredcostscouldhaveamaterialimpactonourresultsofoperations,financialposition fectively prohibitsnewcoal-firedpowerplantsfrombeingconstructeduntilcarboncaptureand gy portfolioofpowergenerationassetsthatincludeafuelmixcoal,naturalgasandwind W . e expecttheEP While wedonotbelievethat any substancesfromoursolidwastedisposalactivitieswill W These disposalareasarecurrentlylocatedbelowsomeshallowwateraquifersinthemine. 2 emissions. yodak, NeilSimpsonI,II, This changewouldincreasedisposalcosts,whichcannotbequantifieduntilthe gy ef W A . toissueaproposedrulein2014andwhilewecannotpredictthetermsof The EP e willalsocloseNeilSimpsonIonorbeforeMarch21,2014. As of W ficiency requirementscouldrequireustoincursignificantadditionalcosts e willcontinuetoreviewGHGimpactsaslegislationorregulation The EP Aug. 31,2012,wesuspendedoperationsatBenFrench,which is A intendstofinalizethefirstGHGemissionstandardssometimein 32 A willalsobedevelopingGHGemissionstandardsforexisting A. Inadditiontofederallegislativeactivity fsets, theacquisitionordevelopmentofadditionalener . . Ofthesegenerationresources,coal-firedpowerplants An applicationtoclosetheimpoundmentwasapproved A 2 ’ emissionsatourexistingplantscouldhaveamaterial s GHG W Annual Inventoryregulation,issuedin2009. T ygen IIand o theextentourregulatedfossil-fuel This rule,withitsverylowproposed Dec. 31,2013,sentcoalashtoa W Ash andwastefromfluegas 1, theEP ygen IIIplantsaredepositedin 1 GHGemissionsfrom A ’ s GHG , GHG T ailoring fect the ground gy FORM 10K 10K | 33 ge gy , we The yoming The Non- W Additionally site in Council e cannot determine the e cannot determine ygen III according to ygen III according W W fset remediation costs. ygen III, Black Hills Power has a Hills Power has ygen III, Black W to remediate the MGP The acquisition provided for a $1.0 Agreement with the successor to the former Agreement with the successor to the former There are potentially other responsible parties There are potentially other responsible The regulations are complex and contain The regulations are The successor is responsible for remediation The successor is responsible for remediation oup Access ygen III. Under their separate but related operating but related operating their separate ygen III. Under W As operator of As operator to $6.3 million . , which will be used to help of 33 $2.9 million $1.3 million egulated Energy Gr , at this time no parties have been named nor have we determined the , at this time no parties have been named will select from to form the final version of the rule. will select from to Non-r A and other agencies to issue orders compelling potentially responsible parties to and other agencies to issue orders compelling ygen I plant, respectively ygen I plant, Aquila received rate orders that approved recovery of environmental cleanup A W Allocation, Indemnification and oluntary Cleanup Program. Site remediation was completed in September 2012. Both oluntary Cleanup Program. Site remediation There are currently no regulatory requirements or deadlines for cleanup. V s fs, Iowa; however s ownership, e anticipate recovery of current and future remediation costs would be allowed. e anticipate recovery of current and future remediation costs would be allowed. , MDU and the City of Gillette each share the costs for solid waste from for solid waste from each share the costs the City of Gillette , MDU and W yodak plant and yodak plant , now valued at approximately ransaction, we acquired whole and partial liabilities for several former manufactured gas processing ransaction, we acquired whole and partial , develops and produces natural gas and crude oil primarily in the Rocky Mountain region. , develops and produces natural gas and crude oil primarily in the Rocky Mountain W T gy Group, which operates through various subsidiaries, produces and sells electric capacity and ener gy Group, which operates through various subsidiaries, produces and sells electric ocessing published its proposed coal combustion residuals regulations. coal combustion residuals regulations. published its proposed Aquila A Airport Generation site in Pueblo, Colo., we posted a bond with the State of Colorado to cover the costs of the costs to cover of Colorado the State bond with posted a Colo., we Pueblo, site in Generation Airport gy Group consists of three business segments for reporting purposes: 1, Nebraska Gas executed an ed Gas Pr Power Generation Coal Mining Oil and Gas . fs, Iowa, of which we could be responsible for up to 25 percent of the costs. fs, Iowa, of which we could be responsible • • • Our Non-regulated Ener and acquires, explores for through a portfolio of generating plants, produces and sells coal from our mine located in the Powder River Basin in through a portfolio of generating plants, produces and sells coal from our mine regulated Ener Agreements are in place that require PacifiCorp and MEAN to be responsible for any costs related to the solid waste from their waste from their related to the solid for any costs and MEAN to be responsible require PacifiCorp are in place that Agreements interest in the ownership facility remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero dischar for this processing and storage wastewater to provide permitted pond containment a waste water for remediation For our Pueblo Pueblo For our similar agreement in place for any such costs related to solid waste from to solid waste from any such costs related in place for similar agreement Black Hills Power agreement, Additional unexpected material costs could also result in the future if any regulatory agency determines that solid waste from future if any regulatory agency determines material costs could also result in the Additional unexpected disposed solid waste. In special treatment, including previously contains a hazardous material that requires the burning of coal treatment. On June dispose of such waste responsible for remedial authority could hold entities that that event, the regulatory 21, 2010, the EP Manufactur their respective ownership interests. their respective ownership ash management that the EP various options for for some time in rule is known, which appears to be scheduled operations until the final version of the likely impact on our have a material impact waste, implementation requirements could subject to regulations as a hazardous 2014. If ash becomes results of operations or cash flows. on our financial position, EP Some federal and state laws authorize the As a result of the clean up sites that are determined to present an actual or potential threat to human health or the environment. clean up sites that are determined to present degree to which they are responsible. Prior to Black Hills Corporation’ costs in certain jurisdictions. sites in Nebraska and Iowa which were previously used to convert coal to natural gas. sites in Nebraska and Iowa which were In March 201 of approximately As of Dec. 31, 2013, we estimate a range million insurance recovery or materially due to results of further investigations, actions of environmental agencies remediation cost estimate could change parties. the financial viability of other responsible operator this agreement, Nebraska Gas received $1.9 million from the successor to the operator of the Nebraska MGPs. Under in Nebraska (Blair and Plattsmouth). for Nebraska Gas to remediate two sites enrolled (Columbus and Norfolk). Subsequent to this transaction, Nebraska Gas activity at the two remaining sites in Nebraska Blair and Plattsmouth in Nebraska’ 2014. groundwater quality for a minimum two-year period to end in September Nebraska sites will be required to monitor Bluf relating to the site in Council Bluf when and where permitted. may pursue recovery or agreements with other potentially responsible parties 34 |10K FORM 10K the PP operation onJan.1,2012,andtheassetsareaccountedfor asacapitalleaseunder20-yearPP combined-cycle gas-firedpowergenerationplantslocated at asitesharedwithColoradoElectric. Black HillsColoradoIPP generating capacityintothewholesalepowermarketswhen itisavailableandeconomical. Cheyenne Lighttoexerciseitsoptionpurchasesometime duringthenextseveralyears. purchase optionatyear million peryear). per megawattadjustedforcapitaladditionsandreducedbydepreciationover35yearsstartingJan.1,2009(approximately $5 ownership interestinthe PP remaining 23.5percent. of 90megawattslocatedatourGillette, Black HillsW approval andcertainotherrequirementsincludedinthecontract. expected toclosein May 6,2013,BlackHills W W Black HillsW (1) ______combination ofmid-tolong-termcontracts,whichmitigatestheimpactapotentialdownturninfuturepowerprices. W Portfolio Management operating in and operatesournon-regulatedpowerplants. Our PowerGenerationsegment,whichoperatesthroughBlackHillsElectricanditssubsidiaries,acquires,develops Power As ofDec.31,2013,thepowerplantownershipinterestsheldbyourPowerGenerationsegmentincluded: year currently sellasubstantialmajorityofournon-regulatedgeneratingcapacityundercontractshavingtermsgreaterthanone Pueblo Wygen I Gillette CT Power Plants e sellexcesspowerfromourgeneratingcapacityintothewholesalemarketswhenitisavailableandeconomical. On e produceelectricpowerfromourgeneratingplantsandsellthecapacityener yo., ener A . thatexpireson PP Black HillsColoradoIPP A GenerationSegment A withColoradoElectric,anyexcesscapacityandener Airport Generation withColoradoElectric. gy complex. W yoming -W yoming -GilletteCT yoming andColoradowithatotalnetownershipofapproximately The netbookvalueof Dec. 31,2022. August 2014upontheexpirationofexistingPP -end 2013,theestimatedpurchasepricewouldhavebeenapproximately $154million.
The facility’ W ygen I. W -Pueblo W e sell60megawattsofunitcontingentcapacityandener ownsandoperatesthisfacility ygen Ifacilitythrough2019. (1) yoming enteredintoanagreementtoselltheGilletteCT This PP The . The GilletteCT The PP Airport Generation. s ener W A isaccountedforasacapitalleaseontheaccompanyingConsolidatedFinancialStatements. ygen Igenerationfacilityisamine-mouth,coal-firedpowerplantwithtotalcapacity W W gy andcapacityissoldtoCheyenneLightunderaPP yo., ener A ygen IatDec.31,2013was$79million includesanoptionforCheyenneLighttopurchaseBlackHills As ofDec.31,2013,weheldvaryinginterestsinindependentpowerplants gy complex. isasimple-cycle,gas-firedcombustionturbinelocatedatourGillette, . Type Coal Fuel The Pueblo This facilityprovidescapacityandener Gas Gas The purchasepriceinthecontractrelatedtooptionis gy shallbeforthebenefitofColoradoElectric. 34 W Gillette, Wyo. Gillette, Wyo. Pueblo, Colo. e own76.5percent Location Airport GenerationStationconsistsoftwo100megawatt A withCheyenneLight. 309 megawatts. Ownership gy fromthisplanttoCheyenneLightundera andifCheyenneLighthadexercisedthe Inter 100.0% 100.0% totheCityofGillette, 76.5% oftheplantandMEANowns est W gy toColoradoElectricundera20-year gy e sellexcesspowerfromour , primarilytoaf A A This saleissubjecttoFERC withColoradoElectric.Under thatexpiresin The plantscommenced Capacity Owned (MW) 308.9 200.0 W W 68.9 40.0 yo. filiates undera yoming’ W August 2014. e expect The saleis $2.6 million In Service 2003 2012 2001 Date s W e
FORM 10K 10K | 35 — — — 402 402 556,577 556,577 557,899 557,899 2011 — 8,011 8,011 Airport Generating 762,950 541,687 762,950 538,945 1,304,637 1,301,895 2012 — . 5,481 5,481 556,307 556,106 fing, and management services from BHSC. 1,008,482 1,564,789 1,008,482 1,564,588 2013 filiate entity yoming are parties to a shared facilities agreement, yoming are parties to a shared facilities gy at wholesale. EWGs are subject to FERC regulation, W for the use of Colorado Electric assets. for the use of Colorado Electric assets. Act of 1992 encouraged independent power production by ygen I and 200 megawatts at the Pueblo 35 , which allows FERC to waive certain accounting, record-keeping W , gy Policy , and foster competition within the wholesale electricity markets. Our Power yoming also receive certain staf W and Colorado Electric are also parties to a facility fee agreement, whereby and Colorado Electric are also parties ges for the use of assets by the af , FERC has taken steps to increase access to the national transmission grid by utility , FERC has taken steps to increase access ges Black Hills Colorado IPP , Cheyenne Light, and Black Hills ges MEAN for administrative services, plant operations and maintenance for their share of the ges MEAN for administrative services, yoming and MEAN are parties to a shared joint ownership agreement, whereby Black Hills yoming and MEAN are parties to a shared The passage of the Ener and Black Hills
W Many of the environmental laws and regulations applicable to our regulated Electric Utilities also Many of the environmental laws and regulations applicable to our regulated Electric e own three EWGs: Gillette CT W Agreements - yoming char ygen I generating facility for the life of the plant. ygen I generating facility for the life of Act of 1992. Colorado Electric char Black Hills Colorado IPP Colorado IPP Black Hills Black Hills Power W W whereby each entity char The independent power industry consists of many strong and capable competitors, some of which may have more The independent power industry consists
Our Power Generation segment has the following material operating agreements: Agreements. Our Power Generation segment has the gy Policy , state regulatory rules requiring utilities to competitively bid generation resources may provide opportunity for , state regulatory rules requiring utilities to competitively bid generation resources Jointly Owned Facilities - Shared Services Black Hills Colorado IPP Black Hills Wyoming Black Hills IPP Black Hills Colorado Black Hills Wyoming IPP Black Hills Colorado Black Hills Wyoming • • ith respect to the merchant power sector Sold Total Sold Generated Total Generated Purchased Total Purchased Quantities Sold, Generated and Purchased (megawatt-hour) and Purchased Generated Sold, Quantities providing certain exemptions from regulation for EWGs. EWGs are exclusively in the business of owning or operating, or both providing certain exemptions from regulation for EWGs. EWGs are exclusively owning and operating, eligible power facilities and selling electric ener including rate regulation. Station. Our EWGs were granted market-based rate authority and reporting requirements imposed on public utilities with cost-based rates. The Ener apply to our Power Generation operations. See the discussion above under the “Environmental” and “Regulation” captions for apply to our Power Generation operations. See the discussion above under the the Utilities Group for additional information on certain laws and regulations. Environmental Regulation. W and non-utility purchasers and sellers of electricity robustly invest in power generation assets. Generation business could face greater competition if utilities are permitted to However independent power producers in some regions. extensive operating experience, or greater financial resources than we possess. extensive operating experience, or greater Competition. Operating The following table summarizes megawatt-hours for our Power Generation segment: Generation Power for our megawatt-hours table summarizes The following 36 |10K FORM 10K coal usingfrontendloadersanduseconveyorstotransportthemine-mouthgeneratingfacilities. explosives. Surface mininginvolvesremovingthetopsoil,thendrillingandblastingoverburden(earthrockcovering coal)with United States. Mining Company bituminous coalatourminenearGillette, Our CoalMiningsegmentoperatesthroughour Coal MiningSegment of Pueblo CT Greenhouse GasRegulations. Power Generationsegmentinasimilarmanner the termsandconditionsofastatepermit. Solid W place. prevention regulations.Eachofourfacilitiesregulatedunderthisprogramhavetherequisitepollutionplansin compliance withdischar above forourElectricUtilities.EachoffacilitiesthatisrequiredtohaveNPDESpermitsthoseandarein Clean W The EP approved PostMining process. Oncewehavereplacedtheoverburdenandtopsoil,re-establishvegetationplantlifeinaccordancewith our disturbed areasaspartofournormalminingactivitiesbyback-fillingthepitwithoverburdenremovedduring we holdsuf result ofSO Air assumptions inpreparingour estimateofrecoverablecoalreserves.SeeRiskFactorsunder CoalMiningforfurtherdetails. coal reservesincludethatcanbeeconomicallyand legallyextractedatthetimeoftheirdetermination. methods ortheutilizationofnewtechnologiesmayincrease ordecreasetherecoverybasisforacoalseam.Ourrecoverable estimates areperiodicallyupdatedtoreflectpastcoalproduction andothergeologicalminingdata.Changesin coal reservelifeisequaltoapproximately utilizing currentlyavailabledrillingdataandgeologicalinformation preparedbyinternalengineeringstudies. estimated ourrecoverablecoalreservestobeapproximately federal andstateroyaltiesof12.5percent9.0percent, respectively generally areextendedtotheexhaustionofeconomicallyrecoverable reserves,aslongactiveminingcontinues. to March31,2021,andthestateleaseexpireson Mining rightstothecoalarebasedonfourfederalleasesand onestatelease. approximately 60percentduring2013. relocated miningoperationstoanareaoftheminewithloweroverburden. coal uncovered,hadinrecentyearstrendedupwards. In abasincharacterizedbythickcoalseams,ouroverburdenratio,comparisonofthecubicyardsdirtremovedto atonof Electric Utilities.OurGilletteCT Clean , Act andhavetherequiredpermitsinplaceorapplicationssubmittedaccordancewithregulatorytimelines. W ygen IandthePueblo Air A aste Disposal. ater ’ s MACT Airport GeneratingStation,uponinitialissuanceofthe Act. ficient allowancesforourGilletteCT W 2 allowancescreditedtousfromtheinstallationofsulfurremovalequipmentatourjointlyowned Act e thenremovetheoverburdenwithequipment.Onceexposed,wedrill,fractureandsystematically W The Clean . e producedapproximately , islocatedinthePowderRiverBasin. The Clean ruledescribedintheUtilitiesGroupsectionwillapplyto W T opography plan. ge limitations. e disposeofall Air W Airport Generatingunitsuponamajormodification,operatingpermitrenewalorinthecase Act impactsourPowerGenerationbusinessinamannersimilartotheimpactdisclosedfor ater TheEP , W Act impactsourPowerGenerationbusinessinamannersimilartotheimpactdescribed ygen IandPueblo A The EP ’ W s GHG ygen Icoalashandscrubberwastesinminedareasatour The factorsdiscussedunderthiscaptionfortheUtilitiesGroupalsoimpactour 40 yearsatthecurrentexpectedproductionlevels.Ourrecoverable coalreserve 4.3 milliontonsofcoalin A . W WRDC subsidiary alsoregulatessurfacewateroilpollutionpreventionthroughits T and Aug. 1,2023. yo. ailoring RuledescribedintheUtilitiesGroupsectionwillapplytoGillette The The overburdenratiodecreasedinthesecondhalfof2012whenwe W Airport Generatingfacilitiesaresubjectto ygen Iplantsthrough2043,withoutpurchasingadditionalallowances. The PowderRiverBasincontainsoneofthelar WRDC coalmine,whichweacquiredin1956fromHomestakeGold 213 million 36 The durationoftheleasesvary;however T . itle W e surfacemine,processandsellprimarilylow-sulfursub- 2013. , ofthesellingpriceallcoal. V tons,basedonalife-of-mineengineeringstudy operatingpermit. The overburdenratiohasbeenreduced W The federalleasesexpirebetweenSept.30,2015, ygen I. T itles IV WRDC coalmineunder As of gest coalreservesinthe , theleaseterms and W Dec. 31,2013,we The recoverable W e reclaim W V yodak plant, oftheClean e usevarious W e pay As a FORM 10K 10K | 37 . Aug. 31, 2012, 31, 2012, Aug. . Costs and other factors s cost-depreciated fective fective ygen 1 plant through June 30, fect the overall demand for This contract expires June 1, This contract expires e sold approximately 120,000 120,000 e sold approximately W . W , 25 percent by MDU and 23 percent , 25 percent by MDU yoming and 23.5 percent by MEAN to yoming and 23.5 percent yodak plant is determined by the coal W W WPSC and the City of Gillette that coal for WPSC and the City of Gillette that coal The price adjustments will be based on the The price adjustments will be based on This contract expires June 30, 2038; and This contract expires . fective March 21, 2014. fective March 37 The agreement with Cheyenne Light provides coal for the life of the The agreement with Cheyenne Light provides ygen I generating facility for requirements under an agreement using a ygen I generating facility for requirements W ear Corporate Bond Index plus 4 percent with the base price being adjusted ear Corporate Bond Index plus 4 percent WRDC will supply coal to the 90 megawatt WRDC will supply coal to the 90 megawatt ygen III. f-site sales have been to consumers within a close proximity to the mine. Rail f-site sales have been to consumers within a close proximity to the mine. Rail , environmental considerations and availability af W filiate coal sales to a specified return on our coal mine’ filiate coal sales to a specified return on A-rated utility bonds, to be applied to our coal mining investment base as A-rated utility bonds, to be applied to our , of gy sources, such as natural gas, wind, solar and hydropower This contract expires at the end of December 2022; This contract expires A-Rated 10-Y yoming for the s W The agreement includes price adjustments in 2014 and 2019, which essentially allow us to The agreement includes price adjustments WRDC coal are limited due to the lower heating value (Btu) of the coal, combined with the WRDC coal are limited due to the lower heating value (Btu) of the coal, combined These laws and regulations often require a lengthy and complex process of obtaining licenses, These laws and regulations often require a lengthy and complex process of obtaining ygen III power plant owned 52 percent by Black Hills Power ygen III power plant yodak power plant owned 80 percent by PacifiCorp and 20 percent by Black Hills Power 80 percent by PacifiCorp and 20 yodak power plant owned The construction and operation of coal mines are subject to environmental protection and land use The construction and operation of coal mines are subject to environmental protection
ygen I power plant owned 76.5 percent by Black Hills ygen I power plant W W W . Black Hills Power made a commitment to the SDPUC, the . Black Hills Power made a commitment The agreement stipulates that These contracts are short-term and have terms of one to three years. These contracts are short-term and have s operating plants would be furnished and priced as provided by that agreement for the life of the Neil s operating plants would be furnished and ’ . The return is 4 percent above Our primary strategy is to sell the majority of our coal production to on-site, mine-mouth generation facilities Our primary strategy is to sell the majority of our coal production to on-site, mine-mouth 10 megawatt , coal competes with other ener WRDC coal mine is served by only one railroad, resulting in less competitive transportation rates. Management WRDC coal mine is served by only one railroad, resulting in less competitive the 1 by the City of Gillette to which we sell approximately 600,000 tons of coal each year to which we sell approximately 600,000 by the City of Gillette 2060; Black Hills Power suspended operations at the 25 megawatt Ben French plant and announced the retirement of the Ben the retirement plant and announced megawatt Ben French operations at the 25 Power suspended Black Hills I plant ef Neil Simpson and the 21.8 megawatt French plant Black Hills Power for use at its Ben French, Neil Simpson I and Neil Simpson II plants. Ef II plants. Neil Simpson I and Neil Simpson French, at its Ben for use Hills Power Black tons per year to Ben French when it was operable and sell approximately 130,000 tons of coal per year to Neil of coal per year to Neil 130,000 tons and sell approximately it was operable to Ben French when tons per year Simpson I; the 362 megawatt PacifiCorp is obligated to purchase a minimum of 1.5 million tons of coal each year of the contract term, subject to tons of coal each year of the contract to purchase a minimum of 1.5 million PacifiCorp is obligated outages. adjustments for planned the 90 megawatt 500,000 tons of coal each year which we sell approximately by truck to which we sell a total of approximately 150,000 tons of coal certain regional industrial customers served each year • • • • • gin equal to the yield for Moody’ ygen II plant. Substantially all of our coal production is currently sold under mid-term and long-term contracts to: contracts and long-term under mid-term sold is currently production of our coal all Substantially Competition. Environmental Regulation. 2038. under long-term supply contracts. Historically relating to these alternative fuels, such as safety coal as a fuel. regulation in the United States. issues and regulations discussed under permits and approvals from federal, state and local agencies. Many of the environmental the Utilities Group also apply to our Coal Mining segment. Additionally base price that includes price escalators and quality adjustments through June 30, 2038, and includes actual cost per ton plus a and quality adjustments through June 30, 2038, and includes actual cost per base price that includes price escalators mar on a 5-year interval. transport market opportunities for fact that the truck transport. continues to explore the limited market opportunities for our product through WRDC supplies coal to Black Hills supply agreement described above. mine's location adjacent to the plant. retain the full economic advantage of the for the avoided costs of rail transportation and a coal unloading facility which market price of coal plus considerations coal from another mine. PacifiCorp would have to incur if it purchased The price for unprocessed coal sold to PacifiCorp for its 80 percent interest in the The price for unprocessed coal sold to W investment base. determined each year Black Hills Power for Simpson II plant and through June 1, 2060, Our Coal Mining segment sells coal to Black Hills Power and Cheyenne Light for all of their requirements under cost-based Black Hills Power and Cheyenne Light for all of their requirements under cost-based Our Coal Mining segment sells coal to these af agreements that regulate earnings from 38 |10K FORM 10K properties andworkinginterestsinsimilarfacilitiesservingournon-operatedMontana W adjacent toourproducingpropertiesinthatarea,andBHEP’ and associatedgatheringsystemlocatedin Kansas) andSacramento(California)basins;(iii)a44.7percentownershipinterestintheNewcastlegasprocessing plant Shale inNorthDakota), (Colorado); (ii)non-operatedinterestsincrudeoilandnaturalgaspropertiesincludingwellslocatedthe Nation inNewMexicoandSouthernUteColorado),thePowderRiverBasin(W gas properties,includingpropertiesintheSanJuanBasin(withholdingsprimarilyontriballandsofJicarilla As ofDec.31,2013,theprincipalassetsourOilandGassegmentincluded:(i)operatinginterestsincrudeoilnatural produces naturalgasandcrudeoilintheUnitedStatesprimarilyRockyMountainregion. Our OilandGassegment,whichconductsbusinessthroughBHEP Oil andGasSegment continue toincrease,whichimposeadditionalcostontheminingprocess. studies, wehaveaccruedapproximately five yearminingpermitissuedbytheStateof other permittingprogramsadministeredbyvariousregulatoryagencies. orderly mining,reclamation,andrestorationofthe must submitapplicationsto,andreceiveapprovalfrom,the Mine Reclamation. power plantsand/orincreasebackfillcostsforthecoalmine. management, handling,storage,transportationanddisposalrequirementswilllikelyincreasethecostofashfor backfill inthenearfuture.Ifashisregulatedasahazardouswaste,implementationrequirementsofmorestringent mine backfill,itiswidelyexpectedthattheU.S.Of ash asahazardouswaste. requirements. PacifiCorp’ Ash istheinor buf vibration andnitrousoxidefumesfromblasting. mining operationsmoveclosertoresidentialdevelopmentareas.Specificconcernscouldincludefugitivedustemissionsand Gillette andtoresidentialindustrialdevelopment.Homeownercomplaintschallengesthepermitsmayoccuras Operations at At Dec.31,2013,wehadtotalreservesofapproximately North Dakota,includingapproximately73grosswellsand 28,000netleaseholdacres. Ef western Colorado,primarilyinMesacounty primarily intheFinn-ShurleyFieldof primarily intheEastBlancoFieldofRio Mountain region. comprised 27percent e alsoownnaturalgasgathering,compressionandtreatingfacilitiesservingtheoperatedSanJuanPiceanceBasin fective July1,2012,wesoldapproximately85percentof our Bakkenand fer zonesthroughlandpurchasesandlong-termleases. s W WRDC mustregularlyaddressissuesarisingduetotheproximityofminedisturbanceboundaryCity The EP ganic residueremainingafterthecombustionofcoal. yodak powerplant,isdisposedofinthemineandutilizedforbackfilltomeetpermittedpost-miningcontour Approximately Reclamationisrequiredduringproductionandaftermininghasbeencompleted.Underapplicablelaw A . The majorityofourreservesarelocatedinselectcrudeoil andnaturalgasproducingbasinsintheRocky hasproposednationaldisposalregulationsthatincludemultipleoptions,oneofwhichregulatescoal W A ind River(W finalruleisexpectedin2014. 31 percentofourreservesarelocatedintheSanJuanBasinnorthwestern NewMexico, W yoming), BearPawUplift(Montana), $21 million eston andNiobraracounties; Arriba County;30percent W . eston County W yoming. T o mitigatetheseconcerns, WRDC mine. fice ofSurfaceMiningwillcollaboratewiththeEP forreclamationcostsasof The currentpermitexpiresin2016.Basedonextensivereclamation 87 Bcfe,ofwhichnaturalgascomprised , While theproposedcombustionresidualsregulationsdonotaddress W WDEQ foranyminingandreclamationplanthatprovides s productionaccountsforthemajorityoffacility’ yoming. 38 W anditssubsidiaries,acquires,exploresfor e haveapprovedminingpermitsandareincompliancewith arelocatedinthePowderRiverBasinof Ash fromour The plant,operatedby The 25 percent WRDC coalmineispermittedtooperateundera WRDC isactivelypursuingtheestablishmentof Three Forksshaleassetsinthe Arkoma (Oklahoma), Dec. 31,2013.Miningregulatoryrequirements W arelocatedinthePiceanceBasinof yoming powerplants,aswell yoming) andthePiceanceBasin W W yoming properties. estern GasPartners,LP 73 percentandcrudeoil Anadarko (T A toaddressmine W W , developsand illiston (Bakken W illiston Basinin yoming, exas and s throughput. Apache , is , we FORM 10K 10K | 39 , . Following these meets with our . Meekins has been so they can prepare their Administration. exas. Reserves were determined were determined exas. Reserves T . Zane Meekins. Mr Additional information on our oil and gas Additional information fer from actual results. Reserves for crude results. Reserves fer from actual orth, to the Consolidated Financial Statements in 20 to the Consolidated is Mr W e elected to only include PUDs which are one location away PUDs which are one location away e elected to only include 39 W . Meekins is a Registered Professional Engineer in the State of . Meekins is a Registered Professional All field and reservoir technical information, which is updated annually All field and reservoir technical information, This definition allows, but does not require us, to book PUD locations but does not require us, to book PUD This definition allows, A&M University in 1987 with a Bachelor of Science in Petroleum exas Access to our reserve database is restricted to specific members of the Access to our reserve database is restricted ferentials are updated in the reserve database and then analyzed to ensure that ferentials are updated in the reserve database T All current financial data such as commodity prices, lease operating expenses, All current financial data such as commodity The primary inputs to the reserve estimation process are comprised of technical information, The primary inputs to the reserve estimation Analysis is the technical person primarily responsible for overseeing our third party reserve Analysis is the technical person primarily responsible for overseeing our third Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Auditing of Oil and Gas Reserves Information promulgated by the Society of fective internal controls over the reserve estimation process as well as the underlying data upon fective internal controls over the reserve e have elected not to report these additional reserve categories. report these additional reserve categories. e have elected not to W . Meekins meets or exceeds the education, training and experience requirements set forth in the Standards . Meekins meets or exceeds the education, training and experience requirements exas Registered Engineering Firm. Our primary contact at CG&A exas Registered Engineering Firm. Our T is a s Manager of Planning and Annual Report on Form 10-K. Annual Report on Form Associates, an independent consulting and engineering firm located in Fort firm located and engineering an independent consulting Associates, e maintain adequate and ef exas and has over 25 years of practical experience in petroleum engineering and over 23 years of experience in the estimation experience in petroleum engineering and over 23 years of experience in the estimation exas and has over 25 years of practical The SEC definition of “reliable technology” allows the use of any reliable technology to establish reserve volumes in addition of any reliable technology to establish of “reliable technology” allows the use The SEC definition by production and flow test data. to those established consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for price for the first-day-of-the-month price calculated using average product using a 12-month with SEC requirements consistent recoverable Estimates of economically of the properties. constant for the life period held 12 months in the reporting each of the which may dif of variables, are based on a number future net revenues reserves and is converted to an MMcfe for a total MMcfe (where oil in Mbbl reported separately and then combined oil and natural gas are Mbbl by six). basis by multiplying location away from a producing well. that are more than one to disclose probable and are allowed, but not required, in our volume reserve estimate. Companies from a producing well possible reserves. The summary information presented for our estimated proved developed and undeveloped crude oil and natural gas reserves gas reserves natural oil and crude and undeveloped proved developed estimated for our presented information The summary Cawley Gillespie reports prepared by is based on future net revenues present value of estimated percent discounted and the 10 & Summary Oil and Gas Reserve Data Gas Reserve Oil and Summary reserves, related financial data and the SEC requirements can be found in Note data and the SEC requirements can reserves, related financial this W data. financial data, ownership interest and production which reserve estimates are based. CG&A is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, operations and land personnel engineers hold technical meetings with geoscientists, operations and land is assessed for validity when the reservoir future development plans. Our internal engineers and our independent reserve to discuss field performance and to validate and and concurrently to develop reserve volume estimates. Current revenue engineering firm, CG&A, work independently audits and accounting records, which are subject to external quarterly reviews, annual expense information is obtained from our internal controls over financial reporting. dif production taxes and field commodity price that all updates are complete. Our current ownership in mineral interests and well they have been entered accurately and in internal controls over financial reporting, and they are incorporated production data are also subject to the aforementioned their accuracy and completeness. Once the reserve database has been entirely the reserve database and verified to ensure relevant technical support materials have been assembled, CG&A updated with current information, and all and future development plans to further verify their validity technical personnel to review field performance updated cost, price and ownership data, is furnished to CG&A reviews the reserve database, including report. independent reserve estimates and final engineering department. practicing consulting petroleum engineering since 1989. Mr practicing consulting petroleum engineering T and evaluation of reserves. He graduated from BHEP’ Engineering. Mr Pertaining to the Estimating and to engineering and geoscience evaluations as Engineers and he is proficient in judiciously applying industry standard practices well as applying SEC and other industry reserves definitions and guidelines. as a geologist and financial analyst. He has estimates. He has over 33 years of exploration and production industry experience reserve estimators in major and mid-sized over 23 years of experience working closely with internal and third party qualified a Masters in Business oil and gas companies. He holds a Bachelor of Science degree in Geology and 40 |10K FORM 10K (a) ______basin, asofDec.31,2013,2012and201 The followingtablessetforthsummaryinformationconcerningourestimatedproveddevelopedandundevelopedreserves,by Total MMcfe Total Undeveloped(MMcfe) Undeveloped - Total DevelopedNon-Producing(MMcfe) Developed Non-Producing- Total DevelopedProducing(MMcfe) Developed Producing- Proved Reserves Total MMcfe Total Undeveloped(MMcfe) Undeveloped - Total DevelopedNon-Producing(MMcfe) Developed Non-Producing- Total DevelopedProducing(MMcfe) Developed Producing- Proved Reserves Oil (Mbbl) Natural Gas(MMcf) Oil (Mbbl) Natural Gas(MMcf) Oil (Mbbl) Natural Gas(MMcf) Oil (Mbbl) Natural Gas(MMcf) Oil (Mbbl) Natural Gas(MMcf) Oil (Mbbl) Natural Gas(MMcf) Reflects saleofthemajorityour Minor differ ences inamountsmayr W illiston Basinassetsin2012 1: esult inthefollowingtablesr Total Total 80,683 77,192 54,086 1,401 2,090 1,622 3,851 86,713 77,053 55,090 4,358 2,966 5,302 5,134 3,661 187 279 78 232 28 40 . Piceance Piceance 12,190 11,855 11,813 21,690 15,150 14,976 2,070 1,986 4,470 4,302 335 335 — — — — 7 elating tooilandgasr 14 28 29 San Juan San Juan 28,688 28,231 28,159 26,937 26,119 26,083 457 457 — — — — 12 635 635 183 183 — — 6 W Dec. 31,2012 Williston Dec. 31,2013 illiston 5,250 1,653 3,597 5,155 1,401 3,754 218 345 479 723 eserves duetor 187 279 489 820 — — — (a) — — — Powder River Powder River 25,988 25,988 28,135 27,481 3,115 7,301 3,321 7,555 ounding. 654 186 — — — — — — — — — 78 Other Other 6,515 5,871 5,739 6,848 6,199 6,007 644 644 649 649 — — — — 22 — — — — 32 FORM 10K 10K | 41 ) ) 1 8 3 (1 21 — 22 — 32 — 823 829 105 8,103 8,229 1,032 1,032 6,377 1,446 6,656 (1,272 10,090 Other Other Other ) ) ) ) — — 77 — 179 641 — 20 — 96 (98 8,747 3,472 (206 (166 (366 29,579 30,220 3,399 3,115 7,735 7,299 River River Powder Powder Powder River Powder ) ) ) ) ) ) (30 (46 676 283 697 425 (126 (106 (251 (164 346 235 1,103 1,067 1,608 7,680 1,756 2,102 1,012 1,394 10,466 19,902 Dec. 31, 2011 Dec. Williston Williston Williston ) ) ) 7 12 — — (1 (5 12 — — — — 854 854 8,132 8,132 2,122 35,609 35,681 44,667 Dec. 31, 2013 Dec. 31, 2013 (3,837 28,618 26,903 San Juan San Juan San Juan — — — ) ) ) 974 974 7 (2 (3 — 68 70 — 1: 628 14,624 14,624 12,765 12,765 28,363 9,830 (1,345 Piceance 12,152 21,265 41 Piceance Piceance 313 ) ) ) ) ) 3,176 5,054 4,517 1,394 68,691 95,793 24,031 32,395 (30 (46 133,242 Total 379 (336 (208 4,116 3,921 3,779 (6,984 55,985 63,190 10,456 Total Total Dec. 31, 2013, 2012 and 201 oved Reserves Natural Gas (MMcf) Natural Gas Natural Gas (MMcf) Natural Gas (MMcf) Oil (Mbbl) Oil (Mbbl) Oil (Mbbl) Production Additions - acquisitions (sales) Additions - extensions and discoveries Revisions to previous estimates Production Additions - acquisitions (sales) Additions - extensions and discoveries Revisions to previous estimates Natural Gas Developed Producing - Developed (in Mbbl) (in MMcf) Crude Oil Total Developed Producing (MMcfe) Total Developed - Developed Non-Producing (MMcfe) Total Developed Non-Producing Undeveloped - Total Undeveloped (MMcfe) Total MMcfe Balance at beginning of year Balance at end of year Balance at beginning of year Balance at end of year Proved Reserves Proved The following tables summarize the change in quantities of proved developed and undeveloped reserves by basin, estimated in quantities of proved developed and undeveloped reserves by basin, estimated The following tables summarize the change using SEC-defined product prices, as of Change in Pr 42 |10K FORM 10K (c) (b) (a) ______(b) (a) ______Balance atbeginningofyear Balance atbeginningofyear T Balance atendofyear Balance atbeginningofyear (in MMcf) Natural Gas Balance atendofyear Balance atbeginningofyear (in Mbbl) Crude Oil Balance atendofyear T Balance atendofyear otal MMcfe otal MMcfe Revisions topreviousestimates Additions -extensionsanddiscoveries Additions -acquisitions(sales) Production Revisions topreviousestimates Additions -extensionsanddiscoveries Additions -acquisitions(sales) Production Revisions topreviousestimates Additions -extensionsanddiscoveries Additions -acquisitions(sales) Production Revisions topreviousestimates Additions -extensionsanddiscoveries Additions -acquisitions(sales) Production Revisions topreviousestimatesfor 2012wereprimarilyduetocommoditypricechanges.Included inthetotalrevisionsis (1,565) MMcfeinvariousbasins. be developedwithinfiveyearsor mustberemovedfromPUDreserves,whichwaspartiallyof MMcfe duetolowercommodity prices, Reflects saleofthemajorityour Production forreservecalculations doesnotincludevolumesforNGLs. Revisions topreviousestimatesfor2013wereprimarilyduecommoditypricechanges. Production forreservecalculationsdoesnotincludevolumesNGLs. (a) (a)
(c) (b) W illiston Basinassetsin2012. (2,422) MMcfefordroppedPUDlocations duetotheSECrequirementthatPUDlocationsmust Total Total Total Total 133,242 (15,220 (12,046 (31,061 (30,885 12,730 80,683 55,985 95,904 86,713 80,683 (9,000 (3,070 (8,686 (2,025 2,526 5,592 2,898 4,116 6,223 (226 (560 449 29 ) ) ) ) ) ) ) ) ) ) Piceance Piceance Piceance Piceance 42 (16,377 (16,369 10,238 12,190 28,363 12,152 28,363 21,677 12,190 (1,357 (1,718 (1,718 1,914 1,884 606 — — — — — — 7 2 5 ) ) ) ) ) San Juan San Juan San Juan San Juan (11,286 (11,282 28,688 44,667 28,618 44,595 26,938 28,688 (3,843 (4,932 (4,926 Dec. 31,2013 Dec. 31,2012 Dec. 31,2012 Dec. 31,2012 2,093 235 235 — — — — 12 — — 12 (1 1 ) ) ) ) ) ) W W Williston Williston fset bypositiveperformancerevisions of illiston illiston (14,968 19,902 (2,455 (3,070 (1,983 2,123 5,155 3,054 1,103 4,056 2,641 5,242 5,155 (226 (920 (890 (104 (427 (338 (378 648 676 401 (45 (b) (b) ) ) ) ) ) ) ) ) ) ) ) ) Powder Powder Powder Powder River River River River 28,135 30,220 26,001 28,135 (1,602 (1,754 7,735 8,926 3,399 3,549 (748 (252 (830 (446 (218 (422 216 343 (42 — 85 — 67 43 ) ) ) ) ) ) ) ) ) (27,051) Other Other Other Other 10,090 (1,278 (1,187 (2,464 (1,169 (2,434 6,515 1,465 6,377 9,964 6,855 6,515
153 — 46 — 46 — 22 — — 21 (3 4 ) ) ) ) ) ) FORM 10K 10K | 43 ) ) ) ) ) 1 (4 — 24 — — 21 — 298 298 9,964 (1,255 (1,721 (1,697 (1,261 10,090 12,768 12,624 117,659 950,231 Other Other Other 2,832,321 1,012,972 1,407,555 1,883,450 1,324,990 9,529,178 ) ) ) ) ) ) ) 6 — — — — Total (Mcfe) (84 (702 (504 (264 (738 (516 3,891 3,549 8,926 (2,100 30,220 33,526 10,180 River River River Powder Powder Powder — — — ) ) ) ) ) 393,892 217,641 281,662 — — — 927 270 2,811,443 3,704,638 (438 (182 (118 (173 7,022 2,014 2,641 2,499 1,460 4,056 (1,265 2,315 MMcfe in various basins. 19,902 14,583 (23,647) MMcfe for dropped PUD Williston Williston Williston NGLs (Gallons) ) ) ) 3 (2 — 11 — — 12 — 1,666 1,648 Dec. 31, 2011 Dec. Dec. 31, 2011 Dec. 31, 2011 (5,075 (5,063 44,667 36,967 11,109 36,901 11,109 44,595 4,661 361,135 163,805 San Juan San Juan San Juan 2,823,795 1,012,972 1,345,021 1,271,715 6,983,104 ) ) ) ) Year ended Dec. 31, 2013 — — — — — — — — (1,077 (1,077 28,363 33,252 16,797 33,252 16,797 28,363 (20,609 (20,609 Natural Gas (Mcfe) 43 Piceance Piceance Piceance — ) ) ) ) ) ) ) ) one percent of total reserve quantities. 1,421 1,044 2,173 — 18,833 (84 fset by positive performance revisions of 927 186,780 125,889 336,140 (504 (452 (108 5,940 6,223 (8,526 35,226 95,456 95,904 29,664 (21,338 (11,238 (20,690 133,242 131,096 Total Total Total Oil (in Bbl) 1 were primarily due to the SEC requirement that PUD locations must be developed within five 1 were primarily due to the SEC requirement (b) Field East Blanco All Others Piceance Finn Shurley All others Bakken Various (a) olumes V Production for reserve calculations does not include volumes for NGLs. Production for reserve calculations does not Revisions to previous estimates for 201 reserves. Included in the total revisions are years or must be removed from proved undeveloped locations due to five year aging of reserves which was of Revisions due to cost and commodity pricing were less than oduction Production Additions - acquisitions Additions - extensions and discoveries Revisions to previous estimates Total Volume Production - acquisitions Additions and discoveries Additions - extensions estimates Revisions to previous Production Additions - acquisitions Additions - extensions and discoveries Revisions to previous estimates otal MMcfe Balance at end of year Location (Basin) Natural Gas (in Mbbl) (in MMcf) T Balance at beginning of year San Juan San Juan Piceance Powder River Powder River Williston All other properties Crude Oil Crude Balance at beginning of year Balance at Balance at end of year of year Balance at beginning Balance at end of year Pr ______(a) (b) 44 |10K FORM 10K Other The followingtablereflectsaveragewellheadpricingused inthedeterminationofreserves: (a) ______(a) ______All otherproperties Williston Powder River Powder River Piceance San Juan San Juan W Powder River Powder River Piceance San Juan San Juan Oil perBbl Gas perMcf thousands) Present valueofestimatedfuturenetrevenues,beforetax,discountedat10percent(in Proved undevelopedreservesasapercentageoftotalprovedonanMMcfebasis Proved developedreservesasapercentageoftotalprovedonanMMcfebasis Location (Basin) All otherproperties Location (Basin) Total Volume Total Volume illiston Consolidated FinancialStatementsinthis The increasetoprovedundevelopedreservesisprimarilydue new wellsdrilled.SeeNote Reflects saleofthemajorityour Information (a) Various Bakken All others Finn Shurley Piceance All others East Blanco All others Finn Shurley Piceance All others East Blanco Various Bakken Field Field W illiston Basinassetsin2012. $ $ Annual ReportonForm10-Kforfurtherdetails. Total 89.79 Oil (inBbl) Oil (inBbl) 3.45 $ $ 451,823 181,580 248,089 202,698 559,971 337,579 16,269 15,757 Piceance 4,139 1,746 1,423 2,514 — — — — 83.92 44 4.02 Natural Gas(Mcfe) Natural Gas(Mcfe) $ $ San Juan Year endedDec.31,2012 Year endedDec.31,2011 8,526,420 1,703,021 1,077,040 4,225,027 1,716,588 1,338,843 3,584,746 8,686,191 1,195,716 94.26 167,367 512,100 837,635 441,165 404,466 Dec. 31,2013 2.85 4,230 4,667 $ $ Williston NGLs (Gallons) NGLs (Gallons) 20 intheaccompanyingNotesto (a) 89.38 4.10 $ As ofDec.31, 3,674,814 2,983,700 2,742,039 3,485,514 $ $ 411,368 240,667 244,339 339,593 159,543 Powder River 39,079 2013 184,372 — — — — — — 90.04 95% 3.79 5% Total (Mcfe) Total (Mcfe) $ As ofDec.31, $ $ 11,762,331 12,543,948 2012 1,786,622 1,262,429 2,426,877 1,111,421 4,235,503 2,049,073 1,751,494 1,338,843 3,593,284 1,259,313 2,452,732 Other 151,255 101,844 837,635 99,209 86.19 3.58 98% 2% FORM 10K 10K | 45 — — — — — — — — — — 1.70 1.70 2.27 3.83 76.13 84.61 Dry Dry Other Other $ $ $ $ 2011 2011 — — — — 1.00 1.73 3.59 6.32 0.99 0.80 0.25 2.04 3.09 4.36 85.73 91.09 An exploratory well is Productive Productive Powder River Powder Powder River $ $ $ $ — — — — — — — — — — 0.19 0.19 2.05 3.07 83.34 85.05 Dry Dry Williston Williston $ $ $ $ 2012 2012 — — — — — — — 1.80 0.74 2.54 0.86 0.86 1.90 3.37 Dec. 31, 2011 Dec. 31, 2012 Dec. 87.47 80.80 1 were insignificant to our overall oil and gas San Juan San Juan Productive Productive $ $ $ $ — — — — — — — — — — — 2.51 3.73 45 1.80 1.80 94.71 Dry Dry Piceance Piceance $ $ $ $ 2013 2013 — — — — — — 2.24 3.59 1.00 0.19 0.80 1.19 1.80 1.00 85.31 88.49 net) development and exploratory wells, with a net well success rate of 95 5 net) development and exploratory wells, Total Total Dec. 31, 2013, 2012 and 201 $ $ $ $ Productive Productive . Gross wells represent the total wells we participated in, regardless of our ownership interest, while . Gross wells represent the total wells we Activity development well is a well drilled within a proved area of a reservoir known to be productive. development well is a well drilled within Activity A Total net development wells Total net exploratory wells San Juan Williston Powder River Other San Juan Williston Powder River Other Year ended Dec. 31, Net Development Wells Piceance Net Exploratory Wells Piceance Year ended Dec. 31, Gas per Mcf Oil per Bbl Gas per Mcf Oil per Bbl Recompletion Recompletion activities for the years ended , we were participating in the drilling of 10 gross (3.18 net) wells, which had been commenced but not yet As of Dec. 31, 2013, we were participating in the drilling of 10 gross (3.18 net) wells, which had been completed. operations. The following tables reflect the wells completed through our drilling activities for the last three years. The following tables reflect the wells completed net wells represent the sum of our fractional ownership interests within those wells. net wells represent the sum of our fractional In 2013, we participated in drilling 38 gross ( Drilling percent. field or to or gas in an unproved area, to find a new reservoir in a previously productive a well drilled to find and/or produce oil extend a known reservoir 46 |10K FORM 10K The followingtablesummarizesourgrossandnetproductivewellsat Productive Total Net Productive: Total Total Net Productive: Total Gross Productive: Gross Productive: Total Net Productive: Total Gross Productive: Natural Gas Crude Oil Natural Gas Natural Gas Crude Oil Natural Gas Crude Oil Crude Oil Natural Gas Crude Oil Natural Gas Crude Oil W ells Total Total Total 613.09 326.57 286.52 570.28 268.42 301.86 621.67 322.57 299.10 1,200 1,224 1,219 762 705 438 519 757 462 Piceance Piceance Piceance 54.76 54.76 60.24 60.24 53.63 53.63 46 — 68 68 — 74 74 — — — 66 66 — San Juan San Juan San Juan Dec. 31,2013,2012and201 199.87 197.96 144.51 142.60 203.31 201.40 1.91 1.91 1.91 214 212 158 156 220 218 2 2 2 Dec. 31,2012 Dec. 31,2013 Dec. 31,2011 Williston Williston Williston 2.44 2.44 3.03 3.03 3.97 3.97 — 53 — — 75 — 53 75 — 56 — 56 Powder River Powder River Powder River 1: 291.82 281.77 295.59 295.38 292.51 292.45 10.05 0.21 0.06 406 441 379 432 399 398 27 9 1 Other Other Other 64.20 63.80 66.91 65.37 68.25 67.48 0.40 1.54 0.77 459 455 476 466 478 472 10 4 6 FORM 10K 10K | 47 , The fect of 1,893 79,925 62,632 90,543 45,680 49,025 Net 329,698 The ef f, locating and Total 99,739 65,739 12,343 96,086 160,287 236,332 670,526 Gross , if production is not Dec. 31, 2013 : Dec. The contract requires us to American tribe, promulgate and 1,727 4,748 29,280 23,199 16,045 19,182 94,181 Net The demand for natural gas is typically The demand for natural gas is typically Developed These tribal laws and regulations include 33,518 24,902 11,049 30,932 26,830 100,209 227,440 Gross , particularly the Bureau of Land Management, the , produce and market crude oil and natural gas. , produce and market crude oil and natural 166 (a) 50,645 39,433 74,498 26,498 44,277 2014, 2015 and 2016, respectively 235,517 Net , and prices of, natural gas and can also temporarily inhibit , and prices of, natural gas and can also fairs, along with each Native , locating and acquiring producing oil and gas properties, , locating and acquiring producing oil and Af e compete with a substantial number of companies ranging from e compete with a substantial number of 47 W e are also subject to various mineral conservation laws and W 1,294 Undeveloped 66,221 40,837 69,256 , which sometimes results in higher natural gas prices. Due to these , which sometimes results in higher natural 129,355 136,123 443,086 Gross American tribe is a sovereign nation possessing the power to enforce laws fective when the infrastructure is placed in commercial service, which is fective when the infrastructure is placed fect the demand for The gatherer is in the process of building the necessary infrastructure to handle the The gatherer is in the process of building . illiston Basin assets in 2012. e believe that our reserves dedicated to the gathering system, and the projected e believe that our reserves dedicated to W W eather conditions af ficient drilling rig and contractor services, receiving economical costs for drilling and other oil and ficient drilling rig and contractor services, W In 2012, we entered into a ten-year gas gathering contract for natural gas production from our In 2012, we entered into a ten-year gas The agreement becomes ef first quarter of 2014. The oil and gas industry is highly competitive. The oil and gas industry is highly competitive.
These regulations include such matters as lease provisions, drilling and production requirements, environmental These regulations include such matters as lease provisions, drilling and production (b) Total illiston established on the leases or further action is not taken to extend the associated lease terms. Decisions on extending leases are based on associated lease terms. Decisions on extending or further action is not taken to extend the established on the leases under the prevailing economic conditions. expected exploration or development potential Reflects the sale of the majority of our Approximately 10 percent (87,689 gross and 23,648 net acres), 19 percent (87,748 gross and 44,136 net acres) and 15 percent (46,458 percent (87,748 gross and 44,136 net acres) (87,689 gross and 23,648 net acres), 19 Approximately 10 percent in of our undeveloped acreage could expire gross and 34,374 net acres) fice of Natural Resources Revenue and the Bureau of Indian Piceance San Juan W Powder River Bear Paw Uplift (MT) Other arious federal agencies within the United States Department of the Interior various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on tribal lands. various taxes, fees and other conditions that apply to lessees, operators and contractors (b) of royalties on federal onshore and enforce regulations pertaining to crude oil and natural gas operations and administration tribal lands. standards and royalty considerations. Each Native and regulations independent from federal, state and local statutes and regulations. Competition. anticipated in the (a) Seasonality of Business. Delivery Commitments. those that have greater financial resources, personnel, facilities and in some cases technical expertise, to a multitude of smaller personnel, facilities and in some cases technical expertise, to a multitude those that have greater financial resources, of these companies explore for aggressive new start-up companies. Many competition are in recruiting and maintaining high quality staf primary areas in which we encounter considerable and development activity acquiring leasehold acreage for drilling locating and obtaining suf transportation for the oil and natural gas we produce. gas services, and securing purchasers and which in turn impacts our overall business plan. production and delay drilling activities, our fiscal year higher in the fourth and first quarters of on a quarterly basis may not reflect results which may be realized on an annual seasonal fluctuations, results of operations basis. under which we will pay a gathering fee per Mcf. properties in the Piceance Basin in Colorado, deliver a minimum of 20,000 Mcf per day committed volumes. Of The following table summarizes our undeveloped, developed and total acreage by location as of location as by total acreage and developed undeveloped, our table summarizes The following Acreage various laws and Operating Regulation. Crude oil and natural gas development and production activities are subject to permits and bonds to drill, complete or regulations governing a wide variety of matters. Regulations often require multiple surface use and restoration of properties on operate wells, and establish rules regarding the location of wells, well construction, be conducted relative to various wildlife and which wells are drilled, timing of when drilling and construction activities can plant stipulations and plugging and abandoning of wells. volumes are adequate to satisfy our delivery commitments under this agreement. volumes are adequate to satisfy our delivery commitments under this agreement. units, the density of wells that may be drilled regulations, including the regulation of the size of drilling and spacing/proration Some states allow the forced pooling or in a given field and the unitization or pooling of crude oil and natural gas properties. and leases cannot be accomplished. integration of tracts to facilitate exploration, when voluntary pooling of lands V ______drill. these regulations may limit the number of wells or the locations where we can 48 |10K FORM 10K well controlthroughouttheconstruction andcompletionphases. aquifers throughoutdrilling,hydraulic fracturingandproductionoperations. recommended practicesandengineering designsisimportanttoensuremechanicalintegrity andisolationfromgroundwater safety andminimizeenvironmental impacts.Ef cementing, completingandproducinggaswellsthatweoperate. Our policyistomeetorexceedallapplicablelocal,state,tribal andfederalregulatoryrequirementswhendrilling,casing, Dec. 19,2013. regulation. Stateregulationsareexpectedtobefinalinearly 2014.NewMexicoincorporatedQuadOregulations,ef In 2013,weparticipatedintheStateofColorado’ completion requirements(directingflowbackgasfromnatural gaswellstosales)dueJanuary2015. requirements). Since201 hazardous airpollutantstandardsforoilandnaturalgasproduction, aswellnaturalgastransmissionandstorage(QuadO for reciprocatinginternalcombustionengines(RICErequirements), newsourceperformancestandardsfor In 201 costs toouroperations. action ontheseproposedrulesisexpectedin2014. U.S. DepartmentoftheInteriorre-proposedrulesregulatingusehydraulicfracturingonFederalandIndianLands. Final even beprecludedfromutilizingfracturestimulationwhichmayef regulations, experiencedelaysorcurtailmentinthepursuitofexploration,development,productionactivities,and perhaps in areaswhereweareconducting,orplantoconductoperations,mayincuradditionalcostscomplywithsuch process, whichmayresultinadditionalregulations.Intheeventfederal,state,localormunicipallegalrestrictionsare adopted several agenciesofthefederalgovernmentincludingEP regulatory authorityovercertainhydraulicfracturingactivitieswhendieselcomprisespartofthefluid.In addition, state regulations. enhance flowofhydrocarbonsintothewell-bore.Chemicalsusedinfracturingprocessarepubliclypostedasrequired by water hydraulic fracturingtechniquesonourcrudeoilandnaturalgasproperties.Ourmixtureis90percent industry toenhancetheproductionofnaturalgasand/oroilfromdensesubsurfacerockformations. Hydraulic fracturingisanessentialandcommonpractice,whichhasbeenusedextensivelyfordecadesintheoil gas species. Certainstates,suchasColorado,imposestormwaterrequirementsmorestringentthantheEP remediation ofpetroleum-productcontamination,identifyingculturalresourcesandinvestigatingthreatenedendangered monitoring, stateairqualitypermitsandunder procedures (suchasspillprevention,controlandcountermeasureplans,stormwaterpollutionpreventiongroundwater requirements relatetothehandlinganddisposalofdrillingproductionwasteproducts,waterairpollutioncontrol environmental regulationsinplanning,designing,drilling,operatingandabandoningwells.Inmostinstances,theregulatory dischar Environmental Regulations. uncertainty withrespecttothetimingandreceiptofpermits. have beengoingthroughsignificantchangeoverthelastseveralyears.Newregulationsincreasedcostsandadded In additiontobeingsubjectfederalandtribalregulations,wemustalsocomplywithstatecountywhich our gas,oilandgatheringoperationsonsuchlands. One ormoreofthesefactorsmayincreaseourcostdoingbusinessontriballandsandimpacttheexpansionviability from regulationsuchasRCRA agencies limitthedisposaloptionsforthosewastes.Itispossiblethatcertainoilandgaswasteswhicharecurrently exempt contamination. cease operationsincontaminatedareas,ortoperformremedialwellpluggingclean-upactivitiespreventfuture waste disposedoforreleasedbyus,priorownersoperators,inaccordancewithcurrentlaws,tootherwisesuspend Under state,federalandtriballaws,wecouldalsoberequiredtoremoveorremediatepreviouslydisposedwaste,including implementing andenforcingtheserequirements. , 9.5percentsandand0.5ofcertainchemicaladditivestofracturethehydrocarbon-bearingrockformation 1 and2012,theEP ge ofmaterialsinto,andtheprotectionenvironment. W W yoming incorporatedQuadOregulationsef The processisregulatedbystateoilandnaturalgascommissions;however e generatewastethatisalreadysubjecttotheRCRA 1, wehavebeenincompliancewiththesenewrequirements andhavebeenmeetingtheQuadOgreen A issuedseveralairqualityregulationsthatimpactouroperations. Ouroperationsaresubjecttovariousfederal,stateandlocallawsregulationsrelatingthe wastesmayinthefuturebedesignatedasunderRCRA ground injectioncontroldisposalpermits),chemicalstorageuseandthe fective wellboreconstruction andcasingdesign,inaccordancewithestablished W s stakeholderprocesstoincorporateEP e takeaproactiveroleinworkingwiththeseagenciestoensurecompliance. All oftheseneworproposedregulationsareexpectedtoresultinadditional A fective Jan.3,2014. W andtheBLMareconductingstudiesoffracturingstimulation 48 e expectadditionalchangesofthisnaturetooccurinthefuture. W W e followindustrybestpracticesforeachprojecttoensure fectively precludethedrillingofwells.InMay2013, e mustaccountforthecostofcomplyingwith andcomparablestatestatutes. W e placepriorityondrillingpractices thatensure A QuadOrequirementsintostate These includeemissionstandards , theEP orotherapplicablestatutes. W A The EP doesassertfederal A e routinelyapply ’ s andareactively VOCs andSO A andvariousstate fective 2 and FORM 10K 10K | 49 e W . e also conduct a W ficient water management ficient water management , storage, shop and warehouse , warehouse building and shop with While this is a requirement in requirement this is a While , storage, shop and warehouse space totaling fective and ef fice, service center The casing is pressure-tested to ensure integrity is pressure-tested The casing This is a permanent program, with GHG emission This is a permanent program, with GHG . Our wells are designed to prevent natural gas and . Our wells are designed e employ qualified companies to monitor the pressure e employ qualified W fice building where our corporate headquarters is located, fice building where our corporate headquarters e use the most ef in 2012. fice, service center operties W A 49 Pr Other e isolate potential sources of ground water by cementing our surface and/ our surface ground water by cementing sources of e isolate potential W The Oil and Gas segment is also impacted by GHG regulation in the state of The Oil and Gas segment is also impacted , 66,000 square foot of fice with approximately 14,300 square feet, and a service center and garage with fice with approximately 14,300 square promulgated an amendment to its GHG reporting requirements in November 2010, to its GHG reporting requirements promulgated an amendment A fice building consisting of approximately 36,600 square feet. fice building consisting of approximately The only subsurface strata connected to the inside of the wellbore are the intervals that we the intervals that of the wellbore are to the inside strata connected The only subsurface The EP
on an annual basis. A yoming, Colorado and Montana we own various of ., we own an of W yo., we own a business of W The handling, storage, and disposal of produced water meets or exceeds all applicable state, local, tribal and or exceeds all applicable state, local, and disposal of produced water meets The handling, storage, , S.D., we own an eight-story yoming, we conduct this sampling in all states in which we conduct these activities. these we conduct in which in all states sampling this we conduct yoming, W 1, with the first annual report submitted to the EP 1, with the first annual report submitted fice building consisting of approximately 36,000 square feet, and a service center fice building consisting of approximately In Rapid City an of approximately 65,000 square feet. approximately 46,600 square feet used for a service center and approximately In Pueblo, Colo., we own a building of 25,700 square feet used for a warehouse. In Cheyenne, an aggregate of approximately 24,400 square feet. an aggregate of approximately 24,400 square In Papillion, Nebr In Nebraska, Iowa, Colorado and Kansas we own various of over 236,500 square feet utilized by our Gas Utilities. In South Dakota, and our Coal Mining segments. space totaling approximately 97,000 square feet utilized by our Electric Utilities e conduct groundwater sampling before and after our drilling and completion activities. activities. completion drilling and after our and before sampling groundwater e conduct • • • • • • owned we own or lease several facilities throughout our service territories. Our In addition to our electric generation facilities, facilities consist of: W Colorado and Colorado between fluids in continuous barrier cement to form a of steel casing and one or more layers are constructed using Our wells the subsurface strata. the well and oil and gas. the purpose of producing perforate for regulations, we will or required by may be necessary additional protection In areas where casing back to surface. or protection string(s) back to surface. production casing intermediate and or cement the may also run a cement bond log to determine the quality of the bond between the cement and the casing and the cement and the the bond between the cement and the bond log to determine the quality of may also run a cement stimulated. are monitored when a well is and/or protection casing string pressures subsurface strata. Surface combination of tests during the life of the well to verify wellbore integrity during the life of the well to verify wellbore combination of tests of the well. from migrating or leaking for the life other produced fluids response to ensure that rate and pressure of fracturing treatment proceeds as planned. Unexpected changes in the rate or proceeds as planned. Unexpected rate and pressure of fracturing treatment response to ensure that evaluated and necessary action taken. pressure are immediately Greenhouse Gas Regulations. options available. and requirements. federal regulatory standards data gathering commenced annual reporting requirements. Initial Natural Gas Systems to the mandatory adding Petroleum and on Jan. 1, 201 reports now due to the EP their own such programs in the future. New Mexico. Other states may implement 50 |10K FORM 10K At Dec.31,2013,certainofourUtilitiesGroupemployeeswerecoveredbythefollowingcollectivebar The followingtablesetsforththenumberofemployeesbybusinessgroup: 27 percentofourUtilitiesGroupemployeeswereeligibleforregularorearlyretirement. collective bar At Dec.31,2013,wehad1,948full-timeemployees. mortgage bondsissuedbyBlackHillsPowerandCheyenneLight,respectively Substantially allofthetangibleutilitypropertiesBlackHillsPowerandCheyenneLightaresubjecttolienssecuringfirst Nebraska Gas Kansas Gas Iowa Gas Colorado Electric Cheyenne Light Black HillsPower Utility Non-regulated Energy Utilities Corporate • • • • • • In additiontoourownedproperties,weleasethefollowingproperties: Other of Approximately 2,000squarefeetofvarious Approximately 108,600squarefeetofvarious to athirdparty; Approximately 48,400squarefeetof Approximately 37,600squarefeetforacustomercallcenterinLincoln,Nebr Approximately 8,800squarefeetforanoperationsandcustomercallcenterinRapidCity Total Total fices andwarehousefacilitieslocatedwithinourserviceareas. gaining agreement. W e havenotexperiencedanylaborstoppagesinrecentyears. Employees Number of fice spaceinDenver 613 161 123 113 144 20 52 fice, servicecenterandwarehousespaceleasedbytheElectricUtilities; fice, servicecenterandwarehousespaceleasedbytheGasUtilities; Approximately America, AFL-CIOLocal6407 Communications Workersof Employees IBEW Local1250 Union Affiliation IBEW Local244 IBEW Local204 IBEW Local667 IBEW Local111 50 , Colo.,ofwhichwesubleaseapproximately10,100squarefeet 31 percentofouremployeesarerepresentedbya . .; Expiration DateofCollective , S.D.; At Dec.31,2013 Bargaining Agreement March 13,2014 March 31,2017 April 15,2015 Dec. 31,2014 June 30,2016 Number ofEmployees July 31,2015 gaining agreements: , approximately 1,948 1,412 145 391 FORM 10K 10K | 51
. our . ficult or fer materially , power sales or other material agreements; gy sources; and The following risk factors and other risk factors risk factors and other risk factors The following 51 . ORS ACT owth strategy gr e development, expansion and acquisition activities may not be successful, which could impair and acquisition activities may e development, expansion RISK F RISK futur e can provide no assurance that we will be able to complete development projects or acquisitions we undertake or development projects or acquisitions that we will be able to complete e can provide no assurance W ent or Our inability to obtain required governmental permits and approvals or the imposition of adverse conditions upon the approvals or the imposition of adverse required governmental permits and Our inability to obtain approval of any acquisition; regulatory proceedings; Our inability to secure adequate rates through terms, or at all; Our inability to obtain financing on acceptable rating agencies would downgrade our issuer credit rating to below investment The possibility that one or more credit business; grade, thus increasing our cost of doing businesses we acquire; Our inability to successfully integrate any key personnel; Our inability to retain management or other construction, fuel supply Our inability to negotiate acceptable acquisition, The trend of utilities building their own generation or looking for developers to develop and build projects for sale to generation or looking for developers to develop and build projects for sale to The trend of utilities building their own utilities under turnkey arrangements; services in the markets we serve; Reduced growth in the demand for utility laws and regulations, particularly those which would make it more dif Changes in federal, state, local or tribal our oil and gas reserves and our generation capacity; costly to fully develop our coal reserves, Fuel prices or fuel supply constraints; Pipeline capacity and transmission constraints; Competition within our industry and with producers of competing ener Changes in tax rates and policies. TING RISKS • • • • • • • • • • • • • • curr that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company understanding of considered for a better the SEC should be reports filed with in our periodic that we discuss ability to execute our ITEM 1A. ITEM The nature of our business subjects us to a number of uncertainties and risks. and risks. uncertainties of us to a number subjects business of our The nature expansion and acquisition ongoing and future development, growth plan is dependent on successful Execution of our future activities. continue to develop attractive opportunities for growth. Factors that could cause our development, expansion, and acquisition that could cause our development, attractive opportunities for growth. Factors continue to develop include: activities to be unsuccessful These important factors and other matters discussed herein could cause our actual results or outcomes to dif our actual results herein could cause matters discussed factors and other These important Our OPERA 52 |10K FORM 10K involves risks,including: Operating electricgeneratingfacilities,oilandgasproperties,thecoalminenaturaldistributionsystems r ar Our facilities involvemanyrisks,including: The construction,expansion,refurbishmentandoperation of powergeneratingandtransmissionresourceextraction facilities involvesignificantriskswhichcouldr Construction, expansion,r esults ofoperations. e notappr financialperformancedependsonthesuccessfuloperationofour • • • • • • • • • • • • • • • Breakdown orfailureofequipmentprocesses,includingthoseoperatedbyPacifiCorpatthe and environmentalregulations,whichcouldlimittheUtilitiesGroup’ the deliveryoffuelduetovariousfactors,includingbutnotlimitedto,transportationdelays,laborrelations,weather purchases fuelfromanumberofsuppliers.Ourresultsoperationscouldbenegativelyimpactedbydisruptionsin Interruptions tosupplyoffuelandothercommoditiesusedingenerationdistribution. Operational limitationsimposedbyenvironmentalandotherregulatoryrequirements; Supply interruptions, workstoppagesandlabor disputes; The costofrecruitingandretaining ortheunavailabilityofskilledlabor; The unavailabilityorincreased costofequipment; The costofsupplyingorsecuringreplacementpowerduring scheduledandunscheduledoutages; Contractual restrictionsuponthetimingofscheduledoutages; satisfying conditionsimposeduponsuchapprovals; The inabilitytoobtainrequiredgovernmentalpermitsand approvals alongwiththecostofcomplyingor agreements. Labor relations. recover inatimelymanner disability Disruption inthefunctioningofourinformationtechnologyandnetworkinfrastructurewhicharevulnerableto maintained byBlackHillsPower W “Legal Proceedings,”afireinvestigatorconcludedthatforestandgrasslandinthewesternBlackHillsof wildfires, polefailuresandassociatedpropertydamageoutages.Forexample,asdescribedinmoredetailunder electrical equipment.Naturalconditionsandotherdisasterssuchaswind,lightningwinterstormscancause Electricity isdangerousforemployeesandthegeneralpublicshouldtheycomeincontactwithpowerlinesor distribution systemwhichcouldimpactpublicsafety Operating hazardssuchasleaks,mechanicalproblemsandaccidents,includingexplosions,af hindered; transmission isinterrupted,ourabilitytosellordeliverproductandsatisfycontractualobligationsmaybe operated byunaf Disrupted transmissionanddistribution. Inability torecruitandretainskilledtechnicallabor; yoming andSouthDakotain2012wascausedbythefailureofatransmissionstructureowned,operated opriately managedor , failuresandunauthorizedaccess.Ifourinformationtechnologysystemsweretofailweunable Approximately filiated parties,todelivertheelectricityandgasthatwesellourretailwholesalecustomers.If efurbishment andoperationofpower , wewouldbeunabletofulfillcriticalbusinessfunctions;and mitigated,our 31 percent , andclaimshavebeenmadeagainstusrelatedtothefire; W educe pr ofouremployeesarerepresentedbyatotalsixcollectivebar operationsmaynotbesuccessfulandthiscouldadverselyaffectour e dependontransmissionanddistributionfacilities,includingthose ofitability , reliabilityandcustomerconfidence; 52 generatingandtransmissionr . facilities.Iftherisksinvolvedinour s abilitytooperatetheirfacilities; The UtilitiesGroup fecting ournaturalgas W esour yodak plant; ce extraction operations gaining
, FORM 10K 10K | 53 , and wet . New plants . Unusually mild ficiency fect electricity demand. fect our profitability and While we maintain insurance, While we maintain fected due to adverse weather or natural fected due to adverse weather or natural conditions. e may not be able to recover the costs incurred in e may not be able to recover the costs incurred W , weather patterns can also af om normal weather 53 Additionally , our utility operations have historically generated lower revenues and , our utility operations have historically fect on our financial condition and results of operations. fect on our financial condition and results Accordingly , strong winds, rain or flooding. , mild temperatures could result in lower electrical demand. These factors could result in interruption of our business, damage to our property such as power lines These factors could result in interruption esults can be adversely affected by variations fr esults can be adversely affected by variations Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, capacity levels, which in turn could cause us to operate below expected Any of these risks could eather interferences; . vailability and cost of fuel supplies; vailability Increased capital and operating costs to comply with increasingly stringent environmental laws and regulations; laws environmental stringent with increasingly to comply costs and operating capital Increased groups; or special-interest of public members by Opposition W A and environmental and geological problems; Unexpected engineering, Unanticipated cost overruns. • • • • • • eather conditions can also limit or temporarily halt our drilling, completion, and producing activities and other crude oil and eather conditions can also limit or temporarily halt our drilling, completion, and summers and winters therefore could have an adverse ef summers and winters therefore could have income when weather conditions are cooler than normal in the summer and warmer than normal in the winter income when weather conditions are cooler could be subject to seasonal natural disasters such as severe snow and ice storms, Our businesses are located in areas that flooding and wildfires. costs associated with these storms. and substations, and repair and clean-up Operating r may employ recently developed and technologically complex equipment, including newer environmental emission control equipment, including newer environmental developed and technologically complex may employ recently technology maintenance costs and penalties. cause us to incur higher operating and increase expenses or of such insurance and meet certain performance levels, the proceeds vendors and obligate contractors to obtain warranties from revenues, increased not be timely or adequate to cover lost or performance guarantees may our rights under warranties payments. expenses, liability or liquidated damage and weather patterns can have a material impact on our operating performance. Our utility businesses are seasonal businesses, in the summer and winter months associated with cooling and heating. Because Demand for electricity is typically greater winter and commercial heating, the demand for this product depends heavily upon natural gas is primarily used for residential first and territory and a significant amount of natural gas revenues are recognized in the weather patterns throughout our service fourth quarters related to the heating seasons. The ongoing operation of our facilities involves many of the risks described above, in addition to risks relating to the risks described above, in addition to of our facilities involves many of the The ongoing operation or ef below expected levels of output of equipment or processes and performance breakdown or failure W curtailed because of cold, snow natural gas operations. Primarily in the winter and spring, our operations can be Our coal mining operations are subject to operating risks that are beyond our control which could af Our coal mining operations are subject restoring transmission and distribution property following these natural disasters through a change in our regulated rates property following these natural disasters through a change in our regulated rates restoring transmission and distribution our results of operations, financial condition and cash flows. thereby resulting in a negative impact on could be disrupted or materially af production levels. Our surface mining operations disasters such as heavy snow increased generating requirements and Extreme temperatures, both hot and cold, cause increased power usage, and therefore, the use of coal. Conversely and completion of new wells or conditions. Severe weather could further curtail these operations, including drilling, could temporarily impair our ability to production from existing wells. In addition, weather conditions and other events transport our crude oil and natural gas production. 54 |10K FORM 10K tar facilities, informationtechnologysystemsandotherinfrastructure facilitiesandsystemsphysicalassets,couldbedirect other disruptiveactivitiesofindividualsorgroups.Ourgeneration, transmissionanddistributionfacilities,fuelstorage disability and networkinfrastructure.Despite ourimplementationofsecuritymeasures,all technologysystemsarevulnerableto W ability toraisecapitalbycontributingfinancialinstability andlowereconomicactivity operations bycontributingtodisruptionofsuppliesandmarkets fornaturalgas,oilandotherfuels. material decreaseinrevenuesandsignificantadditionalcosts torepairandinsureourassets,couldadverselyaf facilities andcapitalimprovementstoexistingfacilities. their abilitytogenerate,purchaseortransmitpowerandby delayingtheirdevelopmentandconstructionofnewgenerating W unpr gr capacity isinadequateor Our procuring someitemsgenerallyincreasedtoseveralmonthsandpricesforthesesignificantly growth exceededsupplyforcertainsurfaceminingequipmentandof demands, ourproductivityandprofitabilitycouldbelowerthancurrentexpectations.Inrecentyears,industry-wide demand cost oftheseincreasesignificantly Our miningoperationrequiresreliablesuppliesofreplacementparts,explosives,fuel,tiresandsteel-relatedproducts. Ifthe ratio. The ratioofcrudeoiltonaturalgaspricesisnearall-timehighlevels,farinexcessthesixoneheatingvalueequiva lent new supplyofcrudeoilandnaturalgas. The proliferationofdomesticcrudeoilandnaturalgasshaleplaysinrecentyearshasprovidedthemarketwithanabundant control. supply ofanddemandforcrudeoilnaturalgas,marketuncertainty these assets.Crudeoilandnaturalgaspricesaresubjecttowidefluctuationsinresponserelativelyminorchangesthe reserves thatarecommerciallyrecoverable,andmayresultinchar decrease incrudeoilornaturalgaspriceswouldnotonlyreducerevenuesandprofits,butalsothequantitiesof Crude oilandnaturalgaspricesmarketshistoricallyhavealsobeen,arelikelytocontinuebe,unpredictable. The successofourcrudeoilandnaturalgasoperationsisaf short periodsoftime. with itsuse. markets. Moreover supply anddemand,weather prices areinfluencedbymanyfactorsoutsideourcontrol,including,amongotherthings,fuelprices,transmissionconstraints, A r Prices for reputation aswell. data couldbecompromised,which couldhaveamaterialadverseef unable torecoverinatimely way Thr current marketrates,orforpenaltiesimposedbystateregulatoryauthorities. responsible fordamagesincurredbyourcounterparties,suchastheadditionalcostofacquiringalternativesupplyat then- is inadequateortransportationdisrupted,ourabilitytosatisfyobligationsmaybehindered. deliver naturalgastoratepayers,supplyourgas-firedpowerplantsandhedgecommoditycosts.Ifstorage capacity Our UtilitiesGroupandPowerGenerationsegmentrelyonpipelinecompaniesotherownersofgasstoragefacilities to evenues andexpensestofluctuatesignificantly portionofournetincomeisattributabletosalescontractand e operateinahighlyregulated industrythatrequiresthecontinuedoperationofsophisticated informationtechnologysystems e aresubjecttothepotentiallyadverseoperatingandfinancial ef oups attemptingtodisruptour gets of,orindirectlyaf eats ofterr operationsr edictable waysandcouldadverselyaffectour There isalsoriskthattheincreaseddomesticcrudeoilresourcescoulddrivepriceslower , failuresorunauthorizedaccess, includingcyber someofour As aresult,wholesalepowermarketsaresubjecttosignificant,unpredictablepricefluctuationsoverrelatively orism andcatastr ely onstorageandtransportationassetsownedbythirdpartiestosatisfyour , unlikemostothercommodities,electricitycannotbestoredandthereforemustproducedconcurrently pr fected by oducts andservicesaswellaportionofour transportationisdisrupted,our , generaleconomicconditions,andtherules,regulationsactionsofsystemoperatorsinthose , wewouldbeunabletofulfill criticalbusinessfunctions,andsensitiveconfidential other , orifsourcesofsuppliesandminingequipmentbecomeunavailabletomeetourreplacement ophic eventsthatcouldr , suchactivities. businesses,or The increaseindomesticnaturalgassupplyhasdrivenpricesdownrecentyears. thebusinessesofthirdparties,mayimpactour . T errorist actsorothersimilareventscouldharmourbusinesses bylimiting r esults ofoperations,financialpositionandliquidity These events,andgovernmentalactionsinresponse,could resultina -attacks. Ifourtechnologysystems weretofailorbebreachedand fected bytheprevailingmarketpricesofcrudeoilandnaturalgas. esult fr abilitytosatisfyour 54 ges toearningsforimpairmentofthenetcapitalizedcost fects ofterroristactsandthreats,aswellcyber fect notonlyonourfinancial results,butonourpublic om terr f-system wholesaleelectricityandnaturalgas.Ener , andavarietyofadditionalfactorsthatarebeyondour operatingcostsar orism, cyber f-the-road tires. obligationsmaybehinder . -attacks, or As aresult,leadtimesfor e volatileandmaycauseour As aresult,wemaybe obligations.Ifstorage They couldalsoimpairour operationsin individualsand/or . . . ed. fect our -attacks and A gy
FORM 10K 10K | 55 . liquidity Agencies that The occurrence of esult in accidents and fect our reputation among among reputation fect our , this action could have a material eate additional costs and cause Act, provide special protection to certain Act, provide special protection to certain ous risks that may r fect on our financial position and results of fect on our financial position and results fect our financial results. In addition, these In addition, results. financial fect our Any such disruption could have a material Any such disruption esults of operations, financial position or esults of operations, may impose significant and sometimes punitive civil may impose significant operations, cr r our 55 impair Act and the Endangered Species A, OSHA, SEC and MSHA A, OSHA, SEC and These types of events could materially adversely af adversely materially events could types of These gy sector are heavily regulated, primarily by agencies of the federal government. regulated, primarily by agencies of the gy sector are heavily These events could disrupt or The FERC, CFTC, EP The FERC, CFTC, egulatory penalties could negatively impact our egulatory penalties These laws and any state equivalents provide for significant civil and criminal penalties for non-permitted These laws and any state equivalents provide These events could result in injury or loss of human life, significant damage to property or natural resources These events could result in injury or loss oduction, transmission and distribution activities involve numer oduction, transmission and distribution ophic events. fect on our operations and/or our financial results. fect on our operations and/or our financial catastr eased risks of r energy pr disruption of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources, could negatively or other fuel sources, infrastructure natural gas pipeline transmission grid, of the regional electric disruption Certain Federal laws, including the Migratory Bird Certain Federal laws, including the Migratory Our historically sought voluntary compliance, or issued non-monetary sanctions, now employ mandatory civil penalty structures for sanctions, now employ mandatory compliance, or issued non-monetary historically sought voluntary regulatory violations. certain aspects of authority business. In addition, FERC delegated compliance requirements relative to our penalties to enforce for violations. If a serious NERC, with similar penalty authority electric system reliability standards to the for enforcement of were imposed by FERC or another federal agency regulatory violation occurred, and penalties adverse ef designated species. species of certain protected animals, including damage to their habitats. If such activities that result in harm to or harassment on, our operations, or if additional species in those areas become subject to protecti are located in an area in which we conduct be transmission, generation, wind, pipeline or drilling projects, could operations and development projects, particularly to implement expensive mitigation measures. restricted or delayed, or we could be required other The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such addressing extent available, to the of insurance, and maintenance measures and guidelines of security The implementation costs. increase could activities impact our business. Because generation, transmission systems and natural gas pipelines are part of an interconnected system, system, are part of an interconnected natural gas pipelines systems and generation, transmission business. Because impact our system an event on the interconnected by the impact of to a disruption caused of business due risk of possible loss we face the significant increase or outage, pipeline rupture, or a sudden or a generator or transmission facility (such as severe weather neighboring system. within our system or within a decrease in wind generation) A Incr on and transmission and distribution activities, as well as our production, transportati Inherent in our natural gas and electricity as leaks, our coal mining operations, are a variety of hazards and operating risks, such storage of crude oil and natural gas and materials, explosions and mechanical problems that could cause substantial adverse blow-outs, fires, releases of hazardous financial impacts. types of events could require significant management attention and resources, and could adversely af could adversely and and resources, attention management significant could require of events types and the public. customers results. impact on our financial the ener Business activities in substantial loss to us. pollution, impairment of our operations, and substantial losses to us. In accordance (including public parks), environmental insurance against some, but not all, of these risks and losses. with customary industry practice, we maintain insurance could have a material adverse ef any of these events not fully covered by populated areas, including residential areas, operations. Particularly for our transmission and distribution lines located near the damages resulting from any such events commercial business centers, industrial sites and other public gathering areas, could be significant. 56 |10K FORM 10K of our If marketor our resultsofoperations,financialpositionorcashflow may berequiredtorefundsuchcosts. and astatepublicutilitycommissionsubsequentlydeterminesthatsuchcostsshouldnothavebeenpaidbythecustomers;we purchased powercosts)withouthavingtofilearatecase. T utility commission. result inratesthatproduceafullrecoveryofourcostsandthereturnoninvestedcapitalallowedbyapplicablestatepublic debt servicecosts,tohavebeenprudentlyincurredorthattheregulatoryprocessinwhichratesaredeterminedwillalways assurance thatthestatepublicutilitycommissionswilljudgeallofourcosts,includingdirectandallocatedborrowingand premised onthefullrecoveryofprudentlyincurredcostsandareasonableratereturninvestedcapital,therecanbeno may ornotmatchourrelatedcostsandallowedreturnoninvestedcapitalatanygiventime. based onananalysisofourcosts,asreviewedandapprovedinaregulatoryproceeding. levels. Ourretailelectricandgasutilityratesareregulatedonastate-by-statebasisbytherelevantstateregulatoryauthorities and stateutilitycommissions. Our regulatedelectricandgasutilityoperationsaresubjecttocost-of-serviceregulationearningsoversightfromfederal ther r Regulatory commissionsmayr Utilities impairment hasoccurred,wearerequiredtorecordanchar whenever eventsorchangesincircumstancesindicateimpairmentmayhaveoccurred.Ifthetestingperformedindicates that which wouldreduceourreportedassets,netincomeandshareholders’ conditions adverselyaf of thegoodwillisrelatedto W income andshar impairment ofour recovery ofourinvestmentinassetssubjecttocondemnation. outcome isuncertain.Ifamunicipalitysoughttopursuethis courseofaction,wecannotassurethatwouldsecureadequate a processthatissubjecttoconstitutionalprotectionsrequiring justandfaircompensation,aswithanyjudicialprocedure,the exercising powersofcondemnationoverallorpartour utility assetswithinmunicipalboundaries. utility withinaportionofourcurrentserviceterritoriesby limitingordenyingfranchiseprivilegesforouroperations,and Municipal governmentswithinourutilityserviceterritories possessthepowerofcondemnationandcouldestablishamunicipal r Municipal governmentsmayseektolimitor may resultinanimpairmentchar assumptions, aboutourbusinessanditsfutureprospectscouldaf competition orchangesintechnologies. in economicconditions,andinterestrates,regulatory assumptions. impairment requiresustomakesignificantestimatesaboutourfutureperformanceandcashflows,aswellother goodwill andtheimpliedfairvalueofinperioddeterminationismade. equest inthefutur ecovery ofour o somedegree,eachofourgasandelectricutilitiesarepermittedtorecovercertaincosts(suchasincreasedfuel e hadapproximately efor utilitybusinesses,wemaybefor e ar e notr other These estimatescanbeaf investmentinassetssubjecttocondemnation. eholders’ conditionsadverselyaffectoperationsor ecoverable, whichcouldadverselyaffectour goodwillr e, or fect operationsinanyofourbusinesses,wemaybeforcedtorecordanon-cashimpairmentchar $353 millionofgoodwillonourconsolidatedbalancesheetsas maydeterminethatamountspassedthr equity This regulatorytreatmentdoesnotprovideanyassuranceastoachievementofdesiredearnings elated totheseutilitieswouldcauseadecr Aquila efuse toappr ge. . Any suchcostsnotrecoveredthroughrates,oranyrefund,couldadverselyaf fected bynumerousfactors,including:futurebusinessoperatingperformance;changes T Any changesinkeyassumptions,oractualperformancecomparedwith ransaction. Ifwemakechangesinourbusinessstrategyorifmarketother ced tor ove someor denyfranchiseprivilegeswhichcouldinhibitour ecord anon-cashgoodwillimpairmentcharge. , industryormarketconditions,changesinbusinessoperations, . T o theextentweareabletopassthroughsuchcostsourcustomers alloftheutilityrateincr 56 r fect thefairvalueofoneormorebusinesssegments,which equir r ough tocustomerswer esults ofoperations,financialpositionor equity e ustomakechangesour ge forthedif ease inour . Goodwillistestedforimpairmentannuallyor ference betweenthecarryingvalueof eases wehaver assetsandar The ratesthatweareallowedtochar Dec. 31,2013. The testingofgoodwillfor e notprudentlyincurr While rateregulationis Any significant abilitytosecur businessstrategyinany Although condemnationis eduction inour equested or A substantialportion liquidity may e adequate ed and net ge, fect . ge FORM 10K 10K | 57 the sale the sale ygen I facility costs could W This power sales esults of The inability to The inability r August 2014 upon August 2014 e estimate our total modeling could ous uncertainties chase option for chase W The accuracy of reserve Act and similar state laws and etation or s ownership interest in the s ownership interest e materially inaccurate, our e materially inaccurate, . Generation segment. Generation WPSC approval in order to obtain regulatory WPSC approval in The process of coal volume estimation requires The process of coal volume estimation yoming’ Power W e obligations ar The resulting estimated reclamation obligations could The resulting estimated reclamation obligations than anticipated. eserve which could adversely affect our 57 r ed sooner eserves may change materially due to numer eserves may change materially due to requires that asset retirement obligations be recorded as a liability based requires that asset retirement obligations The Surface Mining Control and Reclamation The Surface Mining Control and Reclamation could adversely affect our could adversely coal r fect the quantity and quality of our reserve estimates. fect the quantity and quality of our reserve be incurr . GAAP eclamation and mine closur eclamation and mine r easonable rates to fully utilize these assets subsequent to the expiration of long-term of long-term to the expiration these assets subsequent rates to fully utilize easonable ariance from the assumptions used and drill hole modeling density could result in additions or ariance from the assumptions used and drill hole modeling density could result V esults of operations, financial position and liquidity financial esults of operations, r fect on our results of operations and financial condition. fect on our results of operations and financial This purchase by Cheyenne Light would be subject to This purchase by Cheyenne than anticipated or The estimated liability can change significantly if actual costs vary from our original assumptions or if The estimated liability can change significantly eater ee dimensional structural modeling. Significant inaccuracies in interpr ee dimensional structural modeling. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers, and by The estimate of ultimate reclamation liability yoming entered into an agreement to sell its 40 megawatt CTII to the City of Gillette in City of Gillette in CTII to the to sell its 40 megawatt into an agreement yoming entered which expires in December 2022. sales agreement with Cheyenne Light yoming has a power sales contracts at r sales contracts W W
Generation ent in thr ygen I to Cheyenne Light Fuel & Power Cheyenne Light Fuel ygen I to ability to successfully complete the sale of CTII to the City of Gillette and execute the pur and execute of Gillette the City CTII to the sale of complete to successfully ability W There are many uncertainties inherent in estimating quantities of coal reserves. There are many uncertainties inherent in operations. in subsequent computer modeling of the intersected deposit. Significant inaccuracies interpretations of drill hole log data and af interpretation or modeling could materially and geological interpretation, conditions encountered during actual reserve recovery estimates is a function of engineering and undetected deposit anomalies. or geologic changes may occur or become deletions from our volume estimates. In addition, future environmental, economic estimates. known that require reserve revisions either upward or downward from prior reserve materially affect the estimated quantity and quality of our materially affect the estimated quantity be significantly gr inher If the assumptions underlying our If the assumptions Coal Mining Black Hills of obtain power could affect our contracts Black Hills to Cheyenne Light. output of the CTII Hills Power sells the under which Black sales agreement of an existing power expiration included in the contract. to FERC approval and certain other requirements This sale is subject Black Hills an option for Cheyenne Light to purchase agreement includes treatment. operations. Our mining consists of surface mining and closure standards for all aspects of surface mining. regulation establish operations, reclamation requirements, engineering studies, and our engineering expertise related to these reclamation liabilities based on permit requirements. government regulators. government regulations change significantly consider value of the estimated future cash flows. In estimating future cash flows, we on fair value, which reflects the present and apply inflation rates. the estimated current cost of reclamation could the timing of these expenses change significantly from our assumptions, which change significantly if actual amounts or have a material adverse ef Estimates of the quality and quantity of our Estimates of the quality and quantity Power Our between 2013 and 2019. between 2013 and 2019. 58 |10K FORM 10K and resultsofoperations. drilling activitiesmaynotbe successful. Lackofdrillingsuccesscouldhaveamaterial adverse ef active drillingbasins.Highactivity insomebasinsmaycauseshortagesofrigsandequipment inotherbasins.Ourfuture shortages anddelaysarecaused bythehighdemandforrigsandotherneededequipment byalar governmental rulesandregulations andshortagesinordelaysthedeliveryofequipment andservices.Suchequipment conditions, mechanicalproblems, pressureorirregularitiesinformations,titleproblems, weatherconditions,compliancewith be curtailed,delayedorcanceledasaresultofvariety factors,manyofwhicharebeyondourcontrol,includingeconomic operating andothercosts. wells, butalsofromwellsthatareproductivedonotproduce suf we willrecoveralloranyportionofourinvestment.Drilling foroilandgasmayinvolveunprofitableef encountered. Drilling activitiesaresubjecttomanyrisks,includingthe risk thatnocommerciallyproductiveoilorgasreservoirswillbe condition andr Lack ofdrillingsuccesscouldr Exploratory anddevelopmentdrillingar and perhapsevenbeprecludedfromutilizingfracturestimulationef that maybesignificant,experiencedelaysorcurtailmentinthepursuitofexploration,development,productionactivities , we areconductingorinthefutureplantoconductoperations,mayincuradditionalcostscomplywithsuchregulations altogether disclosure, andwellconstructionrequirementsonhydraulicfracturingoperationsorotherwiseseektoban activities Certain stateshaveadoptedorareconsideringadoptingregulationsthatcouldimposemorestringentpermitting,public regulation ofhydraulicfracturingandtorequiredisclosurethechemicalsusedinprocess. introduced beforeCongress,calledtheFracturingResponsibilityand use ofhydraulicfracturingonFederalandIndianLands,withfinalactionexpectedin2014.Inaddition,legislationhas been which mayresultinadditionalregulations.InMay2013,theU.S.DepartmentofInteriorre-proposedrulesregulating the agencies ofthefederalgovernmentincludingEP authority overcertainhydraulicfracturingactivitieswhendieselcomprisespartofthefluid.Inadditionseveral process istypicallyregulatedbystatecrudeoilandnaturalgascommissions;however certain chemicalstofracturethehydrocarbon-bearingrockformationenhanceflowofhydrocarbonsintowell-bore. on ourcrudeoilandnaturalgasproperties.Hydraulicfracturinginvolvesusingmostlywater production ofnaturalgasand/oroilfromdensesubsurfacerockformations. Hydraulic fracturingisanessentialandcommonpracticeintheoilgasindustryusedextensivelyfordecadesto stimulate potentially pr r The potentialadoptionoffederalandstatelegislativer prices afterthedateofestimatemayresultinsubstantialupwardordownwardrevisions. results ofdrilling,testingandproduction,changesinfuturecapitalexpendituresfluctuationscrudeoilnaturalgas cause theactualquantityofourreserves,andfuturenetcashflow those assumedinourestimates. development expenditures,operatingexpensesandquantitiesofrecoverablecrudeoilnaturalgasreservesmayvaryfrom recoverable oilandgasreserves,futurecapitalexpenditurespricesforcrudenaturalgas. of availabledata,engineeringandgeologicalinterpretationsjudgment,theassumptionsusedregardingquantities af including assumptionsrelatingtoeconomicfactors.Significantinaccuraciesininterpretationsorcouldmaterially estimating crudeoilandnaturalgasreservesrequiresinterpretationofavailabletechnicaldatavariousassumptions, There aremanyuncertaintiesinherentinestimatingquantitiesofprovedreservesandtheirassociatedvalue. affect our assumptions couldmateriallyaffecttheestimatedquantitiesandpr uncertainties inher Estimates ofthequantityandvalueour Oil andGas esult inr fect theestimatedquantitiesandpresentvalueofourreserves. . Intheeventfederal,state,localormunicipallegalrestrictionsonhydraulicfracturingareadoptedinareaswhere r estrictions whichcouldincr esults ofoperations. There canbenoassurancethatnewwellsdrilledbyusorin whichwehaveaninterestwillbeproductiveorthat eclude theeconomicdrillingandcompletionofwellsincertainr esults ofoperations. ent inestimatingoilandnaturalgasr The costofdrilling,completingandoperatingwellsisoften uncertain.Ourdrillingoperationsmay These variancesmaybesignificant. esult inuneconomicalinvestmentsandcouldhaveanadverse effectonour ease costsandcausedelaystothecompletionofcertainoilgaswells, e speculativeactivitiesthatmaynotr pr oved oilandgasr A andtheBLMareconductingstudiesoffracturingstimulationprocess eserves. Significantinaccuraciesininterpr 58 egulatory initiativesr The accuracyofreserveestimatesisafunctionthequality , tobemateriallydif eserves maychangemateriallyduetonumer ficient netrevenuestoreturnaprofitafterdrilling, Any significantvariancefromtheassumptionsusedcould A wareness ofChemicals esent valueofour fectively precludethedrillingofwells. W e routinelyapplyhydraulicfracturingtechniques eservoirs. esult incommer ferent fromourestimates.Inaddition, elated tohydraulicfracturingcould , theEP r eserves whichcouldadversely , sand,andasmallamountof A Act, toprovidethefederal doesassertfederalregulatory ge numberofcompaniesin fect onourfinancialcondition cially pr Actual prices,production, forts, notonlyfromdry etations or The processof oductive r financial ous
eserves. The FORM 10K 10K | 59 f as
e may have W operties, which which operties, Annual Report on esults of operations. esults , it could impact our BBB (Positive outlook) by r ability to manage business and e to occur natural gas and oil pr gas and natural gin posting requirements. Such a e. If this wer . Dodd-Frank contains significant derivatives . Dodd-Frank contains significant derivatives 59 s; BBB (Stable outlook) by S&P; and eform legislation could impede our operating costs. to the Notes to Consolidated Financial Statements in this 12 to the Notes to Consolidated other ges in the future if commodity prices drive the SEC-defined prices below levels prices drive the SEC-defined ges in the future if commodity ferent prices and costs are fixed and determinable from applicable contracts for the are fixed and determinable from applicable ferent prices and costs downgrade could also result in counterparties requiring us to post additional downgrade could also result in counterparties ent financial r . ge in the second quarter of 2012 due to the full cost ceiling limitations. of 2012 due to the full cost ceiling ge in the second quarter A outlook) by Moody’ Any excess of the net book value, less deferred income taxes, is generally written of book value, less deferred income taxes, Any excess of the net wo primary factors in the ceiling test are natural gas and crude oil reserve quantities and in the ceiling test are natural gas and crude wo primary factors ed below investment grade in the futur T use of derivative instruments as hedges against fluctuating commodity prices and use of derivative instruments as hedges assets and stockholders' equity and could adversely impact our impact adversely and could equity and stockholders' assets gin”) for such transactions. Dodd-Frank provides for a potential exception from these clearing gin”) for such transactions. Dodd-Frank e also use interest rate derivative instruments to minimize the impact of interest rate fluctuations. e also use interest rate derivative instruments to minimize the impact of interest W Baa2 (Positive cost of capital and our fects. In calculating future net revenues, SEC-defined commodity prices and recent costs are utilized. Such are utilized. Such and recent costs commodity prices revenues, SEC-defined future net fects. In calculating ease in our ease estricting our additional and substantial write-downs of the carrying value of our value the carrying of write-downs substantial and additional egulations included in curr edit ratings could be lower This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated less accumulated test, capitalized costs, Under the ceiling to as a ceiling test. review is referred This quarterly est rates. cr e could incur e could e review the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC on a quarterly rules of the SEC the full cost accounting oil properties under our natural gas and carrying value of e review the e recorded a non-cash impairment char e recorded a non-cash e use crude oil and natural gas derivative instruments for our hedging activities for our oil and gas production activities and e use crude oil and natural gas derivative instruments for our hedging activities would cause a decr cause a would W W basis. value of estimated sum of the present equal to the not exceed an amount income taxes, may and related deferred amortization reserves, less any producing the proved in developing and to be incurred future expenditures revenues less estimated future net tax ef related income utilized except when dif prices and costs are contracts. remaining term of those net revenues. Revisions to the present value of estimated future oil and gas prices, both of which impact SEC-defined crude impact on the present or decrease in prices, can have a material gas and crude oil reserves, or an increase estimates of natural net revenues. value of estimated future non-cash impairment char to record additional 2012 impairment. See Note that precipitated the Our W FINANCING RISKS an expense. Form 10-K. access to capital, our Our issuer credit rating is Fitch. Reduction of our credit ratings could impair our ability to refinance or repay our existing debt and to complete new impair our ability to refinance or repay our existing debt and to complete Fitch. Reduction of our credit ratings could financings on reasonable terms, or at all. Derivatives r collateral under existing or new contracts or trades. In addition, a ratings downgrade would increase our interest expense under or trades. In addition, a ratings downgrade would increase our interest expense collateral under existing or new contracts borrowings under our credit facilities. some of our existing debt obligations, including W our gas utility operations. financial risks by r inter Congress and signed into law In July 2010, Dodd-Frank was passed by certain transactions be cleared resulting in a requirement to post cash collateral regulations, including a requirement that (commonly referred to as “mar that will end-users such as utilities and it includes a number of defined terms and cash collateral requirements for commercial applies to particular derivative transactions and the parties to those transactions. be used in determining how this exception to execute derivative transactions to reduce requirement could have a significant impact on our business by reducing our ability to post collateral may cause significant commodity price and interest rate uncertainty and to protect cash flows. Requirements purposes, or may require us to increase our liquidity issues by reducing our ability to use cash for investment or other corporate could result in additional costs being passed on level of debt. In addition, a requirement for our counterparties to post collateral to us, thereby decreasing our profitability As a result of Dodd-Frank regulations promulgated by the CFTC, we may be required to post collateral to clearing entities for As a result of Dodd-Frank regulations promulgated by the CFTC, we may be were previously classified as swaps have certain swap transactions we enter into. In addition, many of the transactions which mar been converted to exchange-traded futures contracts, which are subject to futures 60 |10K FORM 10K W change basedonactualreturnplanassets,changesininterestratesandanygovernmentalregulations. impact onourfundingrequirementsandtheexpenserecognizedrelatedtotheseplans. Assumptions relatedtofuturecosts,returnoninvestments,interestratesandotheractuarialassumptionshaveasignificant W r our Market performanceor move unfavorablyrelatedtoourphysicalorfinancialpositions,hedgingpoliciesandproceduresarenotfollowed. perform itsobligationsunderthehedgearrangement,iseconomicallyimperfect,commoditypricesorinterestrates activities canresultinlosses.Suchlossescouldoccurundervariouscircumstances,includingifacounterpartydoesnot interest ratesweretochangeinourfavor our commoditypriceandinterestrateexposures,wefor prices andinterestratesbyusingderivativefinancialinstrumentsotherhedgingmechanisms. From timetotime,wehavesoughtlimitaportionofthepotentialadverseef Our from thedatestransactionswereconsummated. accounting canresultinvolatilityreportedresults,eventhoughtheexpectedprofitmar GAAP and financialmarketrisks. W fluctuations inr Our conditions. environment af financing dependonmanyfactors, includingchangesinourcreditratings,the federalorstateregulatory equity of capital andplannedexpenditures) withoperatingcashflow liquidity needs(includingfundsrequiredtomakescheduled principalandinterestpayments,refinancedebtfundworking Our abilitytoexecuteouroperatingstrategyishighlydependent uponouraccesstocapital.Historically operations, financialpositionandliquidity execute our W these restrictionsandtheirimpactonourliquidity Financial ConditionandResultsofOperationsinItem7 this the formofdividendsorloanstous.See“LiquidityandCapital Resources”withinManagement’ declaration bytheBoardofDirectors.Ouroperatingsubsidiaries havecertainrestrictionsontheirabilitytotransferfundsin dividends becausetheydependonourfutureearnings,capitalrequirements,andfinancialconditions,aresubject to W capital ordebtservicefunds. applicable contractualorregulatoryrestrictionsthatmayincluderequirementstomaintainminimumlevelsofcash, working for thatpurpose,whetherbydividendsorotherwise.Inaddition,eachsubsidiary’ form ofdividendsoradvances.Oursubsidiariesareseparatelegalentitiesthathavenoobligationtomakeanyfunds available service ourindebtednessdependontheoperatingcashflowofsubsidiariesandpaymentfundsbythemto us inthe W adversely affectour subsidiaries maynotbeallowedor etir e havetwodefinedbenefitpensionplansandthreenon-pensionpostretirementthatcovercertaineligibleemployees. e usevariousfinancialcontractsandderivatives,includingfutures,forwards,optionsswapstomanagecommodityprice e expecttocontinueourpolicyofpayingregularcashdividends.However e areaholdingcompany e r e maybeunabletoobtainthefinancingneededr pensionplansandother useofderivativefinancialinstrumentscouldr hedgingactivitiesthatar ement plansmayadverselyaffectour ely oncashdistributionsfr doesnotalwaysmatchupwiththegainsorlossesoncommoditiesassetsbeinghedged. ferings andproceedsfromasset sales.Ourabilitytoaccessthecapitalmarketsandcosts andtermsofavailable operatingstrategy fecting ener eported financialr abilitytomeetour changesinother . Ourinvestmentsinoursubsidiariesareprimaryassets.operatingcashflowandabilityto gy companies,volatilityincommodity orelectricitypricesandgeneraleconomicmarket The timingoftherecognitiongainsorlossesontheseeconomichedgesinaccordancewith postr e designedtopr . Lackofcr om our etir maybeunabletomakedividendpaymentsor esults duetoaccountingr ement benefitplans.Incr . Inaddition,eventhoughtheyarecloselymonitoredbymanagement,ourhedging subsidiariestomakeandmaintaindividendsdebtpayments.Our financialobligationsor assumptionscouldr edit atr r . esults ofoperations,financialpositionor otect againstcommoditypriceandfinancialmarketrisksmaycause . easonable rateswouldhaveanadverseeffectonour esult inmaterialfinanciallosses. go thebenefitswewouldotherwiseexperienceifcommoditypricesor efinance debt,fundplannedcapitalexpenditur 60 Annual ReportonForm10-Kforfurtherinformationregarding equir equir , borrowingsundercreditfacilities, proceedsofdebtand easing costsassociatedwithour paydividendstoour ements associatedwithsuchactivities. e ustomakesignificantunplannedcontributions , thereisnoassuranceastotheamountoffuture fects resultingfromchangesincommodity s abilitytopaydividendsusdependsonany loanfundstous,whichcould These estimatesandassumptionsmay shar liquidity gin maybeessentiallyunchanged eholders. s Discussionand T . o theextentthatwehedge definedbenefit The dif , wehaveaddressedour es or r ference in esults of otherwise Analysis of
FORM 10K 10K | 61 fect ers. e W . e maintain fective under W fective while other fecting insurance esults of operations, fect to us if any of the r ficient or ef loss for which we are not loss for which we are A Acts are ef edit risk, late payments and late payments and edit risk, ferently depending on the size of the fected by developments af fected by developments -security risks and dangers that exist in the -security risks and dangers that exist in ithin our utility rates we have generally recovered W Acts could require, among other things, changes to our benefits may adversely affect our ficient to prevent a material adverse ef as amended by the Health Care and Education Reconciliation 61 eased counterparty cr eased counterparty esults of operations, financial position and liquidity financial esults of operations, The 2010 ACA r . Acts will have a substantial impact on health care providers, insurers, s employees. Certain provisions of the 2010 e plans and other otection against all significant losses. otection against all fect our financial results. Our insurance may not be suf fect our financial results. Our insurance The 2010 Acts become available. As benefit costs continue to rise, there can be no assurance that the state public utility As benefit costs continue to rise, there can be no assurance that the state public , oil and gas, including unusual or unexpected geologic formations, pressures, down , oil and gas, including unusual or unexpected health car ovide pr Acts will impact employers and businesses dif fective in future years. Acts”). local events and company-specific events, as well as the financial condition of insur events, as well as the local events and company-specific . . The 2010 , the “2010 Acts will be ef . liquidity The increasing costs and funding requirements associated with our health care plans may adversely af The increasing costs and funding requirements These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and These hazards could result in substantial egional economic conditions may cause incr conditions egional economic easing costs associated with our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by insurance coverage could be adversely and the terms of any available ability to obtain insurance insurance coverage may not pr insurance coverage ganization and the specific impacts on a company’ future recession may lead to an increase in late payments from retail, commercial and industrial utility customers, as well as from retail, commercial and industrial lead to an increase in late payments future recession may Our operations are also subject to all the hazards and risks normally incident to the development, exploitation, production and hazards and risks normally incident to the development, exploitation, production Our operations are also subject to all the transportation of, and the exploration for fully insured could materially and adversely af fully insured could materially and adversely to or liabilities to which the Company may be subject, including but not limited all circumstances and against all hazards with our oil from natural events or inadequate facility maintenance, risks associated environmental hazards, fire-related liability distribution property losses, cyber and gas exploration and production activities, gathering and transportation in pipelines. explosions, uncontrollable flows of oil, gas or well fluids, pollution and other hole fires, mechanical failures, blowouts, environmental risks. pollution and other environmental damage and suspension of operations. destruction of property and equipment, wells, and we participate in insurance coverage maintained by the operators of our insurance coverage for our operated wells such coverage will be suf although there can be no assurances that foregoing events occur Incr international, national, state or international, national, Our A flows from our continuing accounts increase, earnings and cash If late payments and uncollectible our non-utility customers. operations may be reduced. Our insurance, could be af insurance, as well as the cost of such Our ability to obtain Insurance coverage may well as the financial condition of insurers. national, state or local events, as businesses, international, to those presently available to us. at all, or at rates or on terms similar not continue to be available financial position or to our employees and retirees have increased substantially in recent years. The costs of providing health care benefits including costs related to health care plans for our employees and former employees, believe that our employee benefit costs, will continue to rise. National and r National In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to we are unable if our subsidiaries, owned by are utility assets and our company are a holding we because In addition, utility that our to ensure designed measures additional to take be required we could markets, the credit access adequately in be evaluated would measures additional Possible service. and reliable safe to provide capitalized adequately are subsidiaries requirements. applicable regulatory and any prudent financial management market conditions, of then-prevailing the context uncollectible accounts, which could adversely affect our could adversely accounts, which uncollectible our results of operations, financial position or liquidity In March 2010, the President of the United States signed PP Act of 2010 (collectively employers and individuals. or the cost of providing employee benefits. commissions will allow recovery provisions of the 2010 as well as changes to the cost of our plans. current employee benefit plans and in our administrative and accounting processes, and are being evaluated and updated as related The ultimate extent and cost of these changes cannot be determined at this time regulations and interpretations of the 2010 relevant state regulatory authorities based on an Our electric and gas utility rates are regulated on a state-by-state basis by the analysis of our costs, as reviewed and approved in a regulatory proceeding. 62 |10K FORM 10K ef On May20,201 Form 10-Kunderthecaption“EnvironmentalMatters.” pending orfinalstateandEP systems, alongwithadditional monitoringandtestingrequirements. to NeilSimpsonII, circumstances. Itisexpected that allofourplantswillbeincompliancebytheinitial2015 deadline,withtheprimaryimpacts units haveacompliancedeadline of from CoalandOilFiredElectricUtilitySteamGenerating Units(MA On Feb.16,2012,theEP of theseunits,wecannotbeassuredthisrecovery deadline. Neil SimpsonI,OsageandBenFrenchfacilities. deadline forthisruleisMarch21,2014.Engineeringevaluations werecompletedandconfirmedthesignificantimpactonour will likelyresultinmorestringentemissionlimitations,whichcouldhaveamaterialimpactonourcostsofoperations. Recent developmentsunderfederalandstatelawsregulationsgoverningairemissionsfromfossil-fuelgenerating plants W and pr Federal andstatelawsconcerninggr ENVIRONMENT ef timely andaccuratebasis,whichcouldresultinalossofinvestorconfidenceourfinancialreportsorhavematerial adverse exists. of weaknessincontroldesignoref During theirassessmentofthesecontrols,managementorourindependentregisteredpublicaccountingfirmmayidentify areas internal controls.Ourindependentregisteredpublicaccountingfirmisrequiredtoattesttheef Section 404oftheSarbanes-Oxley financial r An effectivesystemofinternalcontr by theIRSinconnectionwithlike-kindexchangetransaction. defending againstthesepenalties,itmayhaveamaterialimpactonourresultsofoperations.Nopenaltiesbeenassessed In certaincircumstances,theIRSmayassesspenaltieswhenchallengingourtaxpositions.Ifwewereunsuccessfulin estimated tobeapproximately$23millionbeforeincometaxef the depreciablecostfortaxpurposesinassetsacquired. However income taxonaworstcasebasisthatcouldbeacceleratedintocurrentpayablewouldapproximately$125million. channels tochallengetheproposedadjustment.Ineventweareunsuccessfulinourchallenge,amountofdeferred reported onouroriginallyfiled2008taxreturn. Adjustment receivedfromtheIRSin The IRShaschallengedourpositionwithrespecttothelike-kindexchange. approximately $125millioninincometaxesassociatedwiththeIPP W these taxpositions,our of againassociatedwiththeassetssoldinIPP W fective, whichprovideforhazardousairpollutant-relatedemission limitsandmonitoringrequirements. fect onourabilitytooperatebusinessoraccesssourcesofliquidity e ownandoperateregulatednon-regulatedfossil-fuelgeneratingplantsinSouthDakota, e havedeferredasubstantialamountoftaxpaymentsthroughvariousplanningstrategiesincludingthedeferral e havedeferr Any controldeficienciesweidentifyinthefuturecouldadverselyaf oduction costsandcouldr , wewouldbeentitledtoataxbenefitassociatedwiththeadditionaldepreciationthatresultfromincreasing Although wewillseekrecoveryfortheremainingnetbook valuesoftheseplantsandprudentdecommissioningcosts eporting. 1, withamendmentsonDec.21,2012,theEP ed asubstantialamountofincometaxr AL W ygen I, RISKS r A esults ofoperations,financialpositionor publishedintheFederalRegisterNationalEmissionStandards forHazardous A W regulationsthatwillimpactourfacilitiesarealsodiscussedinItem1ofthis ygen II, fectiveness, whichmayleadtotheconclusionthatamaterialweaknessininternalcontrol ender Act of2002requiresmanagementtomakeanassessmentthedesignandef April 16,2015,withapathway definedtoapplyforaoneyearextensionduecertain April 2013,theirpositionistodisallowasignificantportionofthegaindeferredas ol maynotbemaintained,leadingtomaterialweaknessesininternalcontr eenhouse gasr W someofour ygen IIIandthe W These unitswillberetiredonorbeforetheMarch21,2014 compliance e disagreewithsuchapositionandwillpursueallavailableIRSand/orlegal .
T generatingunitsuneconomicaltooperateandmaintain. egulations andair ransaction. IftheInternalRevenueServicesuccessfullychallenges elated tovarioustaxplanningstrategies,includingthedeferral W This netcurrenttaxliabilitywouldaccrueinterest,whichis yodak Plantincludinginstallation ofmercurysorbentinjection A 62 ’ fect. s IndustrialandCommercialBoilerregulationsbecame
T liquiditycouldbeadverselyaffected TS), withanef ransaction andthe . emissionsmaymateriallyincr fect ourabilitytoreportfinancialresultsona As statedinarevisedNoticeofProposed fective dateof Aquila W T fectiveness ofthesecontrols. ransaction. yoming, andColorado. April 16,2012. The compliance ease our Annual Reporton . Air Pollutants fectiveness of generation Af fected ol over V arious
FORM 10K 10K | 63 Act, gy fect of Air fect on This rule This ements esults of Any equir r echnology echnology r T A, to propose egulations or , the potentially high cost of s GHG New Source s GHG New fective in June 2010. in June fective ’ fect our results of operation and A vailable Control vailable Control A The EP Additionally o the extent our regulated fossil-fuel . T This rule could have a significant impact on our This rule could have liquidity e governmental laws, r fsets, the acquisition or development of additional ener fsets, the acquisition or development of futur 63 onmental liabilities could also adversely affect our onmental liabilities could also adversely ficiency requirements could require us to incur significant additional costs ficiency requirements could require us , could be expensive and could adversely af , averaged over a three year period. In 2014, we expect the EP year period. In 2014, we expect the , averaged over a three gy ef fectively prohibits simple cycle natural gas combustion turbines from turbines from natural gas combustion simple cycle fectively prohibits essing envir . , environmental and other laws and regulations of federal, state, tribal and local , environmental and other laws and regulations gy addr fect of GHG legislation or regulation on our results of operations, cash flows or financial or regulation on our results of operations, fect of GHG legislation fectively prohibits new coal fired units until carbon capture and sequestration becomes capture and sequestration units until carbon new coal fired fectively prohibits liquidity fsets are allowed, the allocation of emission allowances to specific sources, and the ef allocation of emission allowances to fsets are allowed, the ements or esults of operations, financial position or esults of operations, financial position r maintain compliance with existing or e will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel e will also attempt to recover the emission equir W e expect our environmental compliance expenditures to be substantial in the future due to the continuing e expect our environmental compliance expenditures to be substantial in the future W As proposed, it ef As proposed, , or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted, and new laws , or environmental clean-up costs. In addition, e generally must obtain and comply with a variety of regulations, licenses, permits and other approvals in order to e generally must obtain and comply with ailoring Rule, implementing regulations of GHG for permitting purposes, became ef became purposes, for permitting of GHG regulations Rule, implementing ailoring W e to achieve or T The impact of GHG legislation or regulation on our company will depend upon many factors, including but not will depend upon many factors, including legislation or regulation on our company The impact of GHG regulations. Upon renewal of operating permits for existing facilities monitoring and reporting requirements will be will requirements reporting and monitoring facilities for existing permits of operating renewal Upon regulations. A Due to uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean change legislation, or regulatory changes to the final outcome of federal climate Due to uncertainty as review that could impose more stringent emissions control practices and technologies. control practices stringent emissions could impose more review that in to be final 2013 and is expected in September units was re-proposed steam electric generating Standard for new Performance of 2014. the spring feasible. It also ef and economically technically one-third of their capacity generating more than generating units. emissions from existing steam electric regulations for GHG generating fleet. coal and natural gas estimate the ef we cannot definitively position. cap level, and the that are regulated, the overall GHG emissions of implementation, the GHG sources limited to the timing implemented, the impact will If a “cap and trade” structure is to control or reduce GHG emissions. availability of technologies to which of depend on the degree generating plants from utility and other purchasers of the power generated by those non-regulated power plants. generating plants from utility and other New or more stringent regulations or other ener New or more stringent regulations or other The failur will impact us in the event of a major modification at an existing facility or in the event of a new major source as define d by source as new major of a or in the event facility an existing at modification of a major in the event us will impact EP will result in a Best to existing projects major modifications New projects or implemented. natural gas and coal prices. carbon regulation on of additional emission control equipment, the acceleration of capital relating to, among other things, the installation emissions allowances or of expenditures, the purchase of additional standards we will attempt to recover costs associated with complying with emission generating plants are included in rate base or other requirements. changes impact on our results of operations and financial condition. In addition, future unrecovered costs could have a material or air emissions could render some of our power generating units more expensive in environmental regulations governing uneconomical to operate and maintain. could adversely affect our The GHG The GHG supply from renewable resources, and the closure of certain generating facilities. supply from renewable resources, and the complying with such r operations, financial position or Our business is subject to extensive ener authorities. we expenditure and operating costs. If we fail to comply with these requirements, operate, which can require significant capital or and the imposition of penalties, liens or fines, claims for property damage could be subject to civil or criminal liability personal injury could require additional unexpected and regulations may be adopted or become applicable to us or our facilities, which certain sites, and have a detrimental ef expenditures or cause us to reevaluate the feasibility of continued operations at In connection with certain acquisitions, we assumed liabilities associated with the environmental condition of certain In connection with certain acquisitions, we assumed liabilities associated with and in some cases agreed to indemnify the properties, regardless of when such liabilities arose, whether known or unknown, bring our facilities into compliance or to address former owners of those properties for environmental liabilities. Future steps to contamination from legacy operations, if necessary our business. financial condition. trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of trends toward stricter standards, greater regulation, more extensive permitting assets we operate. 64 |10K FORM 10K in this Capital Resources”underItem 7,“Management’ For additionaldiscussionofour dividendpolicyandfactorsthatmaylimitourabilityto paydividends,see“Liquidityand as the44 Directors declaredaquarterlydividendof expect tocontinuepayingaregularquarterlydividendfor the foreseeablefuture. W Columbia and9foreigncountries. common shareholdersofrecordandapproximately31,000 beneficialowners,representingall50states,theDistrictof Our commonstockistradedontheNew ITEM 5. P included inExhibit95ofthis Information concerningminesafetyviolationsorotherregulatorymattersrequiredbySections1503(a)ofDodd-Frank is ITEM 4. on Form10-K. Item 8,Note Information regardingourlegalproceedingsisincorporatedhereinbyreferencetothe“LegalProceedings”sub-caption within ITEM 3. None. ITEM 1B. regulations aimedatreducingemissions,ouroperationsandfinancialresultscouldbeadverselyimpacted. the volumeofcoaltheypurchasefromusorswitchtoalternativefuelsasaresultexistingfutureenvironmental attractive fuelalternativeforourcustomersandcouldimposeataxorfeeontheproducerofcoal.If decrease Existing orproposedlegislationfocusingonemissionsenactedbytheUnitedStatesindividualstatescouldmakecoalaless emission reductions. propose GHGregulationsforexistingsourcesinJune2014whichareexpectedtocontainstate-specificgoalsoverall equipment, atsubstantialcost,ordiscouragetheuseofcertaincoalscontaininghigherlevelsmercury Reductions inmercuryemissionrequiredbycertainstatesandtheEP emission allowances(someofwhichtheymaypurchase),blendhigh-sulfurcoalwithlow-sulfurorswitchtootherfuels. meet thefederalClean require theinstallationofcostlyemissioncontroltechnologyorimplementationothermeasures.Forexample,inorderto Proposed reductionsinemissionsofmercury in theplanningandbuildingofpowerplantsfuture. of ourcoalsales.Renewableener power plantscouldincreasethecostsofusingcoal,therebyreducingdemandforcoalasafuelsourceandvolumeprice of whicharereleasedintotheairwhencoalisburned.Morestringentenvironmentalregulationsemissionsfromcoal-fueled Coal containsimpurities,includingbutnotlimitedtosulfur sales andthepriceofour could r to coalcombustionor The characteristicsofcoalmaymakeitdifficultfor AR e havepaidaregularquarterlycashdividendeachyearsince theincorporationofourpredecessorcompanyin1941and T II Annual ReportonForm10-K. educe coalconsumption. th consecutiveannualdividend increasefortheCompany 18, “CommitmentsandContingencies AND ISSUERPURCHASESOF MARKET SPECIALIZED DISCLOSURES LEGAL UNRESOL These rulescouldhaveasignificantimpactonourcoalfiredgeneratingassetsandmine. utilizationandtheuseofalternativeenergysour Air PROCEEDINGS pr Act limitsforSO FORREGISTRANT’SCOMMONEQUITY Annual Report. oducts. VED ST gy requirementsandchangestoregulationscouldmakecoalalessattractivefuelalternative As ar AFF esult, coalusersmayswitchtoother Y $0.39 pershare,equivalenttoanannualdividendof ork StockExchangeunderthesymbolBKH. COMMENTS 2 , sulfurdioxides,nitrogenoxides,particulatematter emissionfrompowerplants,coalusersmayneedtoinstallscrubbers,useSO s Discussionand ”, ofourNotestoConsolidatedFinancialStatementsinthis EQUITY coaluserstocomplywithvariousenvir , mercury 64 SECURITIES . Analysis ofFinancialCondition andResultsofOperations” , chlorine,carbonandotherelementsorcompounds,many A willlikelyrequiresomepowerplantstoinstallnew ces for , RELA fuels,whichcouldaffectthevolumeofour At itsJan.30,2014meeting,ourBoardof power TED ST As ofDec.31,2013,wehad4,324 generationasmandatedbystates OCKHOLDER MA $1.56 pershare,marking , orgreenhousegasesmay onmental standardsr . EP A isscheduledto Annual Report TTERS elated 2014 2
FORM 10K 10K | 65 0.380 54.83 47.00 0.370 37.00 33.51 Fourth Quarter Fourth Quarter $ $ $ $ $ $ 55.09 46.62 36.28 30.29 0.380 0.370 ork Stock Exchange Exchange ork Stock Y Third Quarter Third Quarter $ $ $ $ $ $ 50.53 43.19 34.31 31.32 0.380 0.370 Second Quarter Second Quarter $ $ $ $ $ $ 44.32 36.89 35.82 32.18 0.380 0.370 65 First Quarter First Quarter $ $ $ $ $ $ 2013. ransactions, for the last two years were as follows: years the last two for ransactions, T High Low High Low Common stock prices Common Common stock prices Dividends paid per share Dividends share Dividends paid per Year ended Dec. 31, 2012 Year ended Dec. 31, Year ended Dec. 31, 2013 Year ended There were no unregistered securities sold during There were no unregistered securities sold UNREGISTERED SECURITIES ISSUED UNREGISTERED SECURITIES ISSUED Composite Composite Quarterly dividends paid and the high and low prices for our common stock, as reported in the New in the as reported stock, for our common prices and low and the high paid dividends Quarterly 66 |10K FORM 10K ITEM 6. ISSUER PURCHASESOF Net Income Capitalization Ratios Total OperatingRevenues Capitalization Capital Expenditures Pr Income (loss)fromcontinuingoperations Years EndedDec.31, There werenoequitysecuritiesacquiredforthethreemonthsendedDec.31,2013. T (dollars inthousands,exceptpershareamounts) Net incomeavailableforcommonstock otal Non-regulated Energy Utilities maturities Short-term debt,includingcurrent Long-term debt,netofcurrentmaturities Notes payable Common stockequity Long-term debt,netofcurrentmaturities Common stockequity Current maturitiesoflong-termdebt Accumulated depreciationanddepletion Total property,plantandequipment Corporate andintersegmenteliminations operations, netoftax Income (loss)fromdiscontinued operty Assets , PlantandEquipment Total Total capitalization
A vailable for SELECTED FINANCIAL (4) CommonStock EQUITY
SECURITIES $ $ $ $ $ $ $ $ $ (1,269,148) 1,396,948 1,275,852 2,787,196 1,307,748 4,259,445 3,875,178 379,534 115,846 114,962 2013 18,403 84,841 82,500 12,602 DA (884) 100% 50% 47% — T 3% A (1) (2) $ $ $ $ $ $ $ $ $ (1,188,023) 1,173,884 2,552,359 1,232,509 3,930,772 3,729,471 277,000 938,877 103,973 347,980 2012 (15,808) 66 79,588 81,528 88,505 24,725 (6,977) 100% 15% 37% 48% (1) (2) $ $ $ $ $ $ $ $ $ 1,272,188 2,837,218 1,280,409 1,209,336 3,724,016 4,127,083 (934,441) 345,000 431,707 2011 (42,361) 81,860 49,730 40,365 2,473 9,365 100% 866 12% 45% 43% (1) $ $ $ $ $ $ $ $ $ 1,219,691 2,540,501 1,186,050 1,100,270 3,353,509 3,711,509 (861,775) 249,000 496,990 2010 (21,611) 74,563 68,685 63,141 10,189 5,181 5,544 100% 10% 47% 43% (1) $ $ $ $ $ $ $ $ $ 1,198,712 2,300,494 1,015,912 1,084,837 2,973,398 3,317,698 (812,961) 164,500 347,819 2009 57,071 35,245 81,555 18,617 77,269 1,581 4,286 100% 44% 47% 9% (1) (3) FORM 10K 10K | 67 2.00 0.11 2.11 2.00 0.11 2.11 1.42 7.6% 38,969 38,684 38,614 55,151 27.84 2009 $ $ $ $ $ $ $ 1.62 0.14 1.76 1.62 0.14 1.76 1.44 6.3% 39,269 39,091 38,916 56,467 28.02 2010 $ $ $ $ $ $ $ 1.01 0.24 1.25 1.01 0.23 1.24 1.46 4.3% 43,925 40,081 39,864 59,202 27.55 2011 $ $ $ $ $ $ $ 2.02 1.86 2.01 1.85 1.48 6.7% (0.16) (0.16) 44,206 44,073 43,820 65,262 27.84 67 2012 $ $ $ $ $ $ $ (6) 2.62 2.60 2.61 2.59 1.52 8.8% (0.02) (0.02) 44,499 44,419 44,163 67,587 29.35 2013 $ $ $ $ $ $ $ continued A T DA e of Common Stock (in dollars) (in thousands) (5) Shar verage Common Stock Total Total A Continuing operations Discontinued operations Continuing operations Discontinued operations Shares outstanding, end of year Shares outstanding, end Shares outstanding, average diluted Shares outstanding, average Basic earnings (loss) per average share - Basic earnings (loss) per Shares outstanding, average basic Shares outstanding, average Diluted earnings (loss) per average share - Diluted earnings (loss) Earnings (Loss) Per (dollars in thousands, except per share amounts) thousands, except per (dollars in Paid on Common Stock Dividends Years Ended Dec. 31, Years Ended Common Stock Data Common Stock Dividends Declared per Share Book Value Per Share, End of Year Equity (full year) Return on SELECTED FINANCIAL SELECTED 68 |10K FORM 10K Consolidated FinancialStatements inthis and ResultsofOperations,Item 7A,QuantitativeandQualitativeDisclosuresaboutMarket RiskandNote For additionalinformationon ourbusinesssegmentsseeItem7.Management’ (4) (3) (1) ______SELECTED FINANCIAL (7) (6) (5) (2) Generating capacity(MW): Operating Statistics: Years endedDec.31, Coal MiningSegment: Power GenerationSegment: Electric Utilities: Oil andGasSegment: Gas Utilities: Gas sold(Dth) Electric Utilities(ownedgeneration) Coal reserves(thousandsoftons) Transport volumes(Dth) Electric Utilities(purchasedcapacity) T Power Generation(ownedgeneration) Megawatt-Hours Sold Megawatt-Hours Purchased Oil andgasproductionsold(MMcfe) Oil andgasreserves(MMcfe) Megawatt-hours sold: ons ofcoalsold(thousandstons) Retail electric Contracted wholesale Wholesale off-system 201 Discontinued operationsincludepost-closingadjustmentsand relatingtoourEner and a$17millionafter 2009 Netincomeincludesa$28millionnon-cashafter Consolidated FinancialStatementsofthis to our impairment char 201 T Excludes CheyenneLight. During November201 certain interestrateswaps;while2013,2012and2009includea Black Hills 2013 includes million notes. interest expenseonnewdebt,while2012includesanafter for amake-wholepremium,write-of unrealized mark-to-marketgain,respectively ons ofcoaldecreasedin2012duetotheexpirationanunprofitable trainload-outcontract. 1, 2010and2009,theassetssoldinIPP 1 and2010includea Total generatingcapacity Total Megawatt-hourssold (6) W illiston Basinassets.Reservesreflectthesaleof W yoming’ $6.6 millionafter ge toourcrudeoilandnaturalgaspropertiesof s projectfinancingandwrite-of 1, weissued4.4millionsharesofcommonstock,whichdilutedour earningspershareinsubsequentperiods. -tax gainonsaleofa23.5percentownershipinterestin DA (2) $27 million T A continued (7) -tax expenserelatingtothesettlementofinterestrateswapsinconjunction withtheprepaymentof f ofdeferredfinancingcostsrelatingtotheearlyredemptionour$250millionnotesand and Annual ReportonForm10-K. $9.9 millionnon-cashafter Annual ReportonForm10-K.) , relatedtocertaininterestrateswaps.2013alsoincludes 59,097,493 63,821,546 1,564,789 4,642,254 1,456,762 6,456,209 2013 212,595 357,193 86,713
4,285 1,249 5,481 9,529 T 790 150 309 ransaction for2009. f ofdeferredfinancingcosts -tax ceilingtestimpairmentchar -tax make-wholeprovisionof W 68 illiston Basinassets.(SeeNotes $17 millionof $20 million,$1.2 47,358,505 60,480,822 1,304,637 4,598,080 1,652,949 6,591,065 2012 232,265 340,036 -tax unrealizedmark-to-marketloss,respectively 80,683 12,544 4,246 1,318 8,011 859 150 309 fset byanafter W s Discussionand ygen I. . 2012includesanon-cashafter 55,764,154 59,216,132 4,590,800 1,788,005 6,728,325 2011 133,242 256,170 556,577 349,520 ge toourcrudeoilandnaturalgasproperties 11,762 $4.6 millionforearlyredemptionofour$225 5,692 1,624 anda$36million 865 450 309 402 gy Marketingsegmentin2013,2012, -tax gainonsaleof 12 and21oftheNotesto Analysis ofFinancialCondition $7.6 million 55,265,630 59,879,450 4,532,191 1,749,524 6,750,497 2010 131,096 261,860 519,057 468,782 27,734 11,300 non-cashafter 5,931 1,247 687 440 120 4 tothe $19 million -tax ceilingtest after , relatedto -tax expense 56,671,438 55,104,284 -tax 4,403,459 1,692,191 6,740,947 2009 related 119,304 268,000 546,403 645,297 12,463 5,955 1,180 630 430 120 — FORM 10K 69 10K | gy TS MARKET gy AND RESUL AND ABOUT , CONDITION CONDITION TIVE DISCLOSURES DISCLOSURES TIVE A *Utility supplies electric and gas service to Cheyenne, Wyoming and vicinity. *Utility supplies electric and gas service to Cheyenne, Wyoming FINANCIAL YSIS OF YSIS . Our focus on customers - whether they are utility customers - whether they are utility customers . Our focus on customers gy holdings to provide additional products and services to our gy holdings to provide additional products AND QUALIT AND Financial Segment Financial Electric Utilities Gas Utilities Power Generation Coal Mining Oil and Gas 69 ANAL TIVE TIVE A AND AND gy company AND QUANTIT AND TIONS TIONS -focused integrated ener -focused integrated e report our business groups in the following financial segments: the following financial business groups in e report our gy company operating principally in the United States with two major business groups - Utilities and business groups with two major in the United States operating principally gy company gy operations reduces reliance on any single business segment to achieve our strategic objectives. Our gy operations reduces reliance on any single business segment to achieve our W . gy customers - provides opportunities to expand our business by constructing additional rate base assets to by constructing additional rate base opportunities to expand our business gy customers - provides OPERA gy OF RISK MANAGEMENT'S DISCUSSION DISCUSSION MANAGEMENT'S tion a as Utilities as gy operations, mitigates our overall corporate risk and enhances our ability to earn stronger returns for gy operations, mitigates our overall corporate risk and enhances our ability to e are a customer al G tric Utilities tur W oal Mine ower Gener Na P C Oil and G Elec e are an integrated ener e are an integrated Utilities Non-regulated Energy Business Group Business and 7A. and 7A. W service to both utility and non-regulated ener businesses, primarily by increasing our customer base and providing superior customers. Non-regulated Ener Non-regulated with a conservative approach to our non- emphasis on our utility business with diverse geography and fuel mix, combined regulated ener our utility and non-regulated ener shareholders over the long-term. Our long-term strategy focuses on growing both The diversity of our ener Overview: or non-regulated ener wholesale customers. serve our utility customers and expanding our non-regulated ener serve our utility customers and expanding ITEMS 7 & ITEMS tion a
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Na P Elec — 120 430 630 1,180 5,955 12,463 645,297 546,403 268,000 119,304 related 2009 6,740,947 1,692,191 4,403,459 -tax 55,104,284 56,671,438 -tax expense , related to after -tax ceiling test $19 million 4 to the 120 440 687 1,247 5,931 non-cash after 11,300 27,734 468,782 519,057 261,860 131,096 2010 6,750,497 1,749,524 4,532,191 59,879,450 55,265,630 $7.6 million Analysis of Financial Condition 12 and 21 of the Notes to the -tax gain on sale of gy Marketing segment in 2013, 2012, 402 309 450 865 and a $36 million 1,624 5,692 $4.6 million for early redemption of our $225 11,762 ge to our crude oil and natural gas properties 349,520 556,577 256,170 133,242 2011 6,728,325 1,788,005 4,590,800 59,216,132 55,764,154 . 2012 includes a non-cash after ygen I. s Discussion and W fset by an after 309 150 859 8,011 1,318 4,246 12,544 80,683 -tax unrealized mark-to-market loss, respectively 340,036 232,265 2012 6,591,065 1,652,949 4,598,080 1,304,637 60,480,822 47,358,505 $20 million, $1.2 million $17 million of illiston Basin assets. (See Notes 68 W -tax make-whole provision of -tax ceiling test impairment char f of deferred financing costs ransaction for 2009. 309 150 790 T 9,529 5,481 1,249 4,285
86,713 357,193 212,595 2013 6,456,209 1,456,762 4,642,254 1,564,789 63,821,546 59,097,493 , related to certain interest rate swaps. 2013 also includes , related to certain interest rate swaps. 2013 Annual Report on Form 10-K.) $9.9 million non-cash after Annual Report on Form 10-K. and f of deferred financing costs relating to the early redemption of our $250 million notes and f of deferred financing costs relating to the -tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment of -tax expense relating to the settlement of interest rate swaps in conjunction with the prepayment (7) continued A T $27 million (2) DA -tax gain on sale of a 23.5 percent ownership interest in 1, we issued 4.4 million shares of common stock, which diluted our earnings per share in subsequent periods. 1, we issued 4.4 million shares of common stock, which diluted our earnings per share s project financing and write-of ge to our crude oil and natural gas properties of $6.6 million after yoming’ W illiston Basin assets. Reserves reflect the sale of the W (6) Total Megawatt-hours sold Total Megawatt-hours Total generating capacity 1, 2010 and 2009, and the assets sold in the IPP 1 and 2010 include a ons of coal decreased in 2012 due to the expiration of an unprofitable train load-out contract. ons of coal decreased in 2012 due to the expiration of an unprofitable train load-out contract. unrealized mark-to-market gain, respectively for a make-whole premium, write-of an after interest expense on new debt, while 2012 includes million notes. 2013 includes Black Hills During November 201 Excludes Cheyenne Light. T certain interest rate swaps; while 2013, 2012 and 2009 include a certain interest rate swaps; while 2013, 2012 impairment char to our Consolidated Financial Statements of this 2009 Net income includes a $28 million non-cash after and a $17 million after Ener Discontinued operations include post-closing adjustments and operations relating to our 201 201 Wholesale off-system Contracted wholesale Retail electric ons of coal sold (thousands of tons) Megawatt-hours sold: Oil and gas reserves (MMcfe) Oil and gas production sold (MMcfe) Megawatt-Hours Purchased Megawatt-Hours Sold Power Generation (owned generation) Power Generation T Electric Utilities (purchased capacity) Electric Utilities Transport volumes (Dth) Coal reserves (thousands of tons) Electric Utilities (owned generation) Electric Utilities Gas sold (Dth) Gas Utilities: Oil and Gas Segment: Electric Utilities: Power Generation Segment: Coal Mining Segment: Years ended Dec. 31, ended Dec. Years Statistics: Operating capacity (MW): Generating (2) (5) (6) (7) (3) (4) For additional information on our business segments see Item 7. Management’ about Market Risk and Note and Results of Operations, Item 7A, Quantitative and Qualitative Disclosures Consolidated Financial Statements in this SELECTED FINANCIAL SELECTED ______(1) 70 |10K FORM 10K technologies. generation. construction ofnewcoal-fired powerplants,webelievethatnaturalgaswillbethenear regulatory emphasisonwindandsolarpowerresources, environmentalregulationsandlegislationthatwilllimit proving upthesubstantialMancosshalegaspotentialofour SanJuanandPiceanceBasinproperties.Givenincreased strong relationshipswithmineralowners,landownersand regulatory authorities. continue toprudentlygrowanddevelopourexistinginventory ofcrudeoilandnaturalgasreserves,whilewestrivetomaintain new supplyofnaturalgas,andhasreducedprevailing gasprices. The proliferationofdomesticnaturalgasproductionfrom shale playsinrecentyearsprovidesthedomesticmarketanabundant recovery toprovidefaireconomicreturnsonourutilityinvestments. maintaining ourhighcustomerserviceandreliabilitystandards inacost-ef infrastructure andconstructionofnewrate-basedpowergeneration facilitiesneededtoprovidesafe,reliableener meet ourobligationstoserveprojectedcustomerdemandand tocomplywithenvironmentalmandatesthroughexpansionof In ournaturalgasandelectricutilities,wewillcontinuetoworkwithregulatorsinexistingserviceterritories ensure we increases duringaperiodoffinancialhardship. interest ratesaccountformuchofthetrendinlowerreturn,alongwithactionsbystatecommissionstomoderate rate around 10percent,andtheaverageregulatorylagislessthan12months,accordingtoEdisonElectricInstitute.Falling local economies. for costrecoveryduetothegeneralstateofeconomyandconcernsthatutilityrateincreasesmaycausefurtherharm to State regulatorycommissionshavebecomemoreconservativeregardingauthorizedreturnsandothermechanisms satisfactory raterecoveryonthiscapitalspending. considerations willpresentachallengetoener grid technologiesandchangesintheeconomy with newstateandfederalenvironmentalregulationsrenewableportfoliostandards.Increasedener The electricutilityindustryisfacingrequirementstoupgradeaginginfrastructure,deploysmartgridtechnologyand comply ef Our objectiveistobebest-in-classrelativecertainoperationalperformancemetrics,suchassafety ficiency • • • • • • • • Powder RiverBasinandreceivedanawardfromtheStateof Our coalminecompletedthreeyearswithfavorableMSHA rate iscurrentlyontracktobebelowindustryaverage; wind farmcomparedtoanindustryaverageof4.4forconstruction.OurCheyennePrairieconstruction compared toanindustryaverageof4.4fornatural-gasfiredplants,and0duringconstructiontheBuschRanch for coal-firedplants,1.3duringtheconstructionofPueblo with a Our OSHA Our safetyrecordisexemplarywitha percent, 94percentand96respectively rate of0.9comparedtoanindustryaverage1.4 for diesel-firedplantsand99percentwindgenerationin2013whiletheindustryaverages^ Our powergenerationfleetavailabilitywas97percentforcoal-firedplants,gas-fired approximately 97percent Our naturalgasgenerationfleetachievedastartingreliabilityof99percentin2013whiletheindustryaveraged 2012 data) natural gasplantsin2013,comparedtoanindustryaverage Our powergenerationfleetachievedaforcedoutagefactorof2.5percentforcoal-firedplantsand1.3 Midwest; Our JDPowerCustomerSatisfactionSurveyindicatedourElectricandGasUtilitieswerefavorabletopeersinthe compared toindustryaverages Our powergenerationfleetachieved1 , customerserviceandcostmanagement.Ournotableoperationalperformancemetricsfor2013include: Additional gas-firedpeaking resources willalsoberequiredtoprovidecriticalback-up supplies forrenewable TCIR rateof2duringtheconstruction The averageawardedreturnonequityforinvestor ;
TCIR rateduringconstructionofourgeneratingfacilitiesisalsosignificantlybetterthanindustryaverage ( ** IEEE DataBase2012) ^^
( ^^ 2012 EdisonElectricInstitute,lessthan83.96minutesandIEEE,93minutes) , however gy companiestryingtobalancecapitalspendingrequirementswhileobtaining TCIR rateof1.7comparedtoanindustryaverage2.8 st QuartileReliabilityrankingwithlessthan65minutes(SAIDI)in2013 , suppressdemandinmanyareasoftheUnitedStates. (^NERC DataBase,2012mostrecentindustryinformation) ; + forDAR W 70 ygen IIIcoal-firedplantcomparedtoanindustryaverageof5.1 -owned utilitiesoverthepastyearhasbeenaveraging * safetyresultscomparedtoothermineslocatedinthe T of7percentand5percent,respectively W ( Airport GeneratingStationnatural-gasfiredplant + yoming forthreeyearswithoutalosttimeaccident. This trendislikelytocontinue. Most recentindustryaveragesare2012); ficient manner W e intendtofocusournear -term fuelofchoiceforpower , ourgoalistosecureappropriaterate , availability gy ef *
were 86percent,92 for Therefore, wewill ficiency TCIR andaDAR -term ef ( These competing * ; NERC GADS gy , reliability . By , newsmart forts on TCIR **
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FORM 10K 10K | 71 gest These riders will ficiency in converting The current regulatory regulatory The current As a result, coal-fired result, coal-fired As a ficient power generation ficient power generation These skills, combined with our These skills, combined e provide power at reasonable rates to our e provide power at reasonable W ficiently planning, constructing and operating rate- ficiently planning, Our Company began as a vertically-integrated electric Our Company began , as we invest in and operate ef , as we invest in and e leverage our mine-mouth coal-fired generating capacity e leverage our mine-mouth coal-fired generating W . Business Strategy 71 gy operations. Utility operations can contribute substantially to the s electric supply for the foreseeable future. for the foreseeable supply s electric forts to expand our utility operations into other markets, most likely in e aggressively manage each of these factors with the goal of achieving low e aggressively manage each of these factors . Our access to coal and natural gas reserves allows us to be competitive as a . Our access to coal and natural gas reserves W Key Elements of our forts to develop additional markets for our coal production. additional markets forts to develop filiates and other load-serving utilities. filiates and other load-serving yoming and South Dakota during the construction of Cheyenne Prairie. W A's proposed and expected GHG regulations, will likely limit construction of new conventional of new conventional likely limit construction regulations, will and expected GHG A's proposed fer several advantages including: For more than 130 years we have provided reliable utility services, delivering quality and value to our For more than 130 years we have provided reliable utility services, delivering e intend to grow our non-regulated power generation business by continuing to focus on long-term by continuing to focus on long-term non-regulated power generation business e intend to grow our fectively transmit and distribute electricity to our customers. distribute electricity to our customers. fectively transmit and W . Low production costs can result from a variety of factors, including low fuel costs, ef . Low production costs can result from , and low per unit operation and maintenance costs. , and low per unit operation and maintenance e have investigated and will continue to investigate the possible deployment of these technologies at our mine at our mine of these technologies the possible deployment to investigate and will continue e have investigated gy gy demand; W , compared to industry benchmarks. , superior customer service, community involvement and a relationship-based approach to regulatory matters. Utility , superior customer service, community involvement and a relationship-based - since the generating assets are included in the utility rate base and reviewed and approved by government Customers - since the generating assets are included than if the power was purchased from the open market through wholesale authorities, customer rates are more stable contracts that are renegotiated over time; where long-term investments are designed to match long-term Regulators - regulators participate in a planning process ener reasonable, stable rate of return may be earned on their investment; Investors - investors are poised that a long-term, ratings which, in turn, can benefit both consumers and investors by All - a lower risk profile may improve credit lowering our cost of capital. yoming and will continue ef yoming and This business model remains a core strength and strategy today This business model W . • • • • e have a competitive power production strategy e have a competitive power production e have expertise in permitting, constructing and operating power generation facilities. constructing and operating e have expertise in permitting, resources to cost ef fuel into ener W utilities consistent with our regional focus and Expand utility operations through selective acquisitions of electric and gas strategic advantages. understanding of electric resource planning and regulatory procedures, provide a significant opportunity for us to add long-term procedures, provide a significant opportunity resource planning and regulatory understanding of electric shareholder value. with our af contractual relationships earnings by ef rates for customers and increase Provide stable long-term utilities. facilities needed to serve our electric base power generation utility for our investors. customers, and earn competitive returns power generator the lar producer by eliminating fuel transportation costs which often represent which strengthens our position as a low-cost we construct this plant to accommodate growth reduce the total cost of the plant ultimately passed along to our customers while and replace plants that were closed prematurely due to environmental regulations. customers. Our tradition of accomplishment supports ef Our actions to provide power at reasonable rates to our customers are exemplified in our successful request to secure the Our actions to provide power at reasonable rates to our customers are exemplified construction financing riders in areas that permit us to take advantage of our intrinsic competitive advantages, such as baseload power generation, system areas that permit us to take advantage of our intrinsic competitive advantages, reliability operations also enhance other important business development opportunities, including gas transmission pipelines and storage operations also enhance other important business development opportunities, infrastructure, which could promote other non-regulated ener Rate-base generation assets of resources will remain a necessary component of the nation’ component remain a necessary will resources levels of for many other utilities. In addition, we typically operate our plants with high component of the delivered cost of coal availability production costs. stability of our long-term cash flows, earnings and dividend policy Currently approximately 40 percent of electricity generated in the United States is from coal-fired power plants. It will take It will take plants. power from coal-fired States is United in the generated of electricity 40 percent approximately Currently technologies. alternative with can be replaced generation this before expense and significant decades W coal-fired power plants, but technologies such as carbon capture and sequestration should provide for the long-term economic economic provide for the long-term sequestration should carbon capture and such as power plants, but technologies coal-fired use of coal. site in climate, combined with the EP climate, combined 72 |10K FORM 10K value creationovermanagingforgrowthasfollows: through bothor gas andcrudeoil.Ourstrategyistocost-ef Increase thevalueofouroilandgaspropertiesbyprudently growingourreservesandincreasingproductionofnatural increases forourutilitycustomers. incorporating renewableener considerations andadministrativelegislativemandates. renewable ener priced, reliablesourcesofener prices forelectricityandnaturalgas. Mandates fortheuseofrenewableener GHG emissionreductionsisalsounderconsideration. considering legislationsettingGHGemissionsreductiontar requiring utilitiestomeetcertainthresholdsofrenewableener sources. of legislationandregulationintendedtoreduceGHGemissionsincreasetheuserenewableotheralternative ener mindful ofcustomerrateimpacts Proactively integratealternativeandrenewableenergyintoourutilitysupplywhilemitigatingremaining III. of Gillette, that wehaveestablishedwithwholesalepowercustomersdevelopedintootheropportunities.MEAN,MDUandtheCity greater returnsoverthelongtermthanwecouldbysellingener help ourcustomersmeettheirener products, suchascapacity believe wewillcontinuetobeaprimaryproviderofelectricitywholesaleutilitycustomers,whichneed generation business. Build andmaintainstrongrelationshipswithwholesalepowercustomersofbothourutilitiesnon-regulated they advanceourlong-termstrategyandmaximizeshareholdervalue. utility assetsandoperationsofothercompaniesonreasonabletermsconditions. industry simplifies theintegrationofpotentialfutureutilityacquisitions.Mer recently announcedtheacquisitionofanotherin easily integratedintoouroperations. W e haveandwillcontinuetopursuethepurchaseofsmall,privateormunicipalnaturalgasdistributionsystems,whichcanbe • • • • • • . T properties, and participatinginselectoilexploration prospectswithsubstantial upsideopportunities; our neartermef existing crudeoilandnatural gasoperationsaswellourpowergenerationactivities. Specifically Primarily focusontheRocky Mountainregion,wherewecanmoreeasilyintegratenew opportunitieswithour Participate inalimitednumber ofselectiveandmeaningfulexplorationprospects; Through detailedreservoiranalysis, applyproventechnologiestoourexistingassets maximizevalue; ener In allstatesinwhichweconductelectricutilityoperations, weareexploringotherpotentialbiomass,solarandwind Black HillsPowerandCheyenneLight; PP expectation thattherewillbemandatoryrenewableener ener In statessuchasSouthDakotaand Colorado’ W mitigate thelong-termcustomerrateimpactofaddingrenewableener Where permitted,wewillseektoconstructrenewablegenerationresourcesasratebaseassets,whichhelp we pursuecost-ef Colorado legislativemandatesapplytoourelectricutilitysegmentregardingtheuseofrenewableener W o date,manystateshaveenactedandothersareconsideringsomeformofmandatoryrenewableener ind site,a29megawattwindturbineproject,wascompletedinthefourthquarterof2012,aspartourplantomeet e believethatimpactsoftherecentrecessionmayproduceopportunitiesforhealthyutilitycompaniestoacquire W As wepurchaseatotalof60megawattswindener gy projects,particularlywindgenerationsiteslocatednear ourutilityserviceterritories. gy yo. werewholesalepowercustomersthatarenowjointownersintwoofourplants, gy standardsandGHGemissionreductionsthatbalancesourcustomers’ ganic growthandacquisitions. , wehaveproactivelyintegratedcost-ef s RenewableEner W e strivetobuildstrongrelationshipswithotherutilities,municipalitiesandwholesalecustomers. forts onfullydeveloping thesubstantialshale gaspotentialofourSanJuan andPiceanceBasin , inordertoreliablyservetheircustomers.Byprovidingtheseproductsunderlong-termcontracts,we fective initiativeswiththeregulatorsthatwillallowustomeetourrenewableener gy intoourresourcesupply gy toourcustomers. . gy needs. The ener At thesametime,asaregulatedutilityweareresponsibleforprovidingsafe,reasonably gy Standard. W e purchasedseveralsmallsystemsinKansasandIowathepastthreeyears, gy orthereductionofGHGemissionswilllikelyproducesubstantialincreasesin fectively growourreservesandincreaseproductionof naturalgasandcrudeoil gy andutilityindustriesfacetremendousuncertaintyrelatedtothepotentialimpact W Through thisapproach,wealsobelievecanearnmorestablerevenuesand yoming thatcurrentlyhavenolegislativemandateontheuseofrenewable While consistentgrowthremainsourobjective,weemphasize managingfor W This sitealsohassignificantexpansionpotential; yoming. As aresult,weemploycustomer fective renewableener , whileseekingtominimizethemagnitudeandfrequencyofrate gets. Federallegislationforbothrenewableener W W e haveascalableplatformofsystemsandprocesses,which gy use. e attempttostrikethisbalancebyprudentlyandproactively 72 gy intomorevolatilespotmarkets.Inaddition,relationships gy fromwindfarmslocatednearCheyenne, gy standardsinthefuture.Forexample,undertwo20-year ger andacquisitionactivityhascontinuedintheutility Additionally gy intoourgenerationsupplybasedupon gy supplies.Forexample,theBuschRanch , manystateshaveeitherenactedorare W -centered strategyforcomplyingwith e expecttoconsidersuchopportunitiesif rateconcernswithenvironmental W ygen Iand gy standardsand , weintendtofocus gy requirements. W gy standard, yo. foruseat gy . Therefore, W ygen W e gy FORM 10K 10K | 73 While fective
When All of our An example of e intend to grow . W gy primarily to load- , we require prepayment, Access to capital has been gy operations. Sustained growth e expect to prioritize small-scale facilities that e expect to prioritize o mitigate these risks, we implemented risk o mitigate these risks, we implemented T W e mitigate this risk by conducting business with a e mitigate this risk by conducting business W e establish counterparty credit limits and employ continuous e establish counterparty credit limits and 73 W gy portfolio with an emphasis on regulated utilities provides growth The plant commenced operations on Jan. 1, 2012, under a 20-year The plant commenced operations on Jan. . e expect much of our growth in the next few years will come from ospective Information W Pr e have demonstrated our ability to access the debt and equity markets, resulting e have demonstrated our ability to access W e will require access to the capital markets to fund our planned capital investments e will require access to the capital markets W fective management of price and operational risks related to adverse changes in fective management of price and operational e remain focused on prudently managing our operations and maintaining our overall e remain focused on prudently managing our operations and maintaining our overall W , increases our ability to earn attractive returns. , increases our ability fective management of counterparty credit risk. fective management of counterparty credit Although dependent on market conditions, we are confident in our ability to obtain additional financing, as Although dependent on market conditions, we are confident in our ability to obtain gy and capacity from our non-regulated power facilities is sold under mid- and long-term contracts. sold under mid- and long-term contracts. our non-regulated power facilities is gy and capacity from and Fitch each upgraded our corporate credit rating during 2013, which helped us obtain financing for $525 and Fitch each upgraded our corporate , to continue our growth plans. Support the future capital requirements of our drilling program by stabilizing cash flows with a hedging program that program a hedging flows with cash by stabilizing program drilling of our requirements capital the future Support future; and in the three years for up to production of our established a portion risk for price commodity mitigates of mid-stream acquisition or the construction with activities gas production natural oil and our crude Enhance value of our operations. the economic manner that maximizes facilities in a compression and treating gathering, s, S&P ge-scale generation projects. ge-scale generation ficient liquidity and solid cash flows. • • e expect to generate long-term growth through the expansion of integrated and diverse ener e expect to generate long-term growth through the expansion of integrated and , when possible, to make strategic acquisitions that prudently grow our businesses. Our access to adequate and cost-ef , when possible, to make strategic acquisitions Selectively grow our non-regulated power generation business in targeted regional markets by developing assets and selling assets and selling by developing regional markets business in targeted power generation grow our non-regulated Selectively utilities. to load-serving contracts primarily mid- and long-term production through capacity and energy most of the Diligently manage the credit, price and operational risks inherent in buying and selling energy commodities Diligently manage the credit, price and much of our recent power plant development has been for our regulated utilities, we intend to continue to expand our non- to continue to expand utilities, we intend been for our regulated development has recent power plant much of our based on prevailing supply power plants in regional markets business by developing and operating regulated power generation capabilities. our existing fuel assets and marketing in a manner that complements and demand fundamentals, primarily in the western facilities and disciplined acquisitions the development of new power generation this business through provides us a competitive and electric transmission fundamentals our detailed knowledge of market region, where we believe advantage and, consequently to permit and construct resources, and are typically easier or provide critical back up to renewable serve incremental growth than lar Most of the ener assumes the fuel risk. whereby the contract counterparty long-term contracts as tolling arrangements, possible, we structure ener of our non-regulated capacity and will continue to focus on selling a majority Going forward, we that have been reviewed or approved by state utility commissions. serving utilities under long-term agreements gas-fired generation constructed by our non-regulated power generation this strategy is the 200 megawatts of combined-cycle utility subsidiary subsidiary to serve our Colorado Electric tolling agreement. operations require ef In certain cases where creditworthiness merits security diverse group of creditworthy counterparties. of financial collateral. secured letters of credit or other forms opportunities, yet avoids concentrating business risk. our long-term strategic plan. liquidity to meet our operating, capital and financing needs, as well as executing Maintain an investment grade credit rating and ready access to debt and equity capital markets. Maintain an investment grade credit rating Moody’ million in debt at favorable terms. credit monitoring, with regular review of compliance under our credit policy by our Executive Risk Committee. Our oil and gas of compliance under our credit policy by our Executive Risk Committee. Our credit monitoring, with regular review ef and power generation operations require liquidity of the commodity markets. commodity prices and the volatility and oversight committees monitor compliance with these policies. management policies and procedures. Our and will continue to be critical to our success. or our investment-grade issuer credit rating. financing depends upon our ability to maintain W requires continued capital deployment. Our diversified ener refinanced much of our highest cost debt on major capital investments at our existing business segments. During 2013, we favorable terms. necessary in suf 74 |10K FORM 10K approximately 400customers. distribution systemsandinfrastructure.InJanuary2014,Cheyenne Lightannouncedthependingacquisitionofassetsserving Similar totheGasUtilitiesdiscussedbelow costs areincludedinRegulatoryassetsuntilthenextratecase filing. contractors thatwereincurredintheef defer theincrementalcostsofapproximately$2.5million, includinglabor annual storm-relatedcostsandinDecember2013,BlackHills PowersubmittedanapplicationtotheSDPUCforapproval Hills Powercustomersexperiencingpoweroutages.Repairing thesubstantialandwidespreaddamagefarexceededaverage In October2013,theCityofRapid following regulatoryrequestsrelatedtoconstructionactivities: Pursuant topriorapprovedresourceplansandpendingelectricrateincreaserequests,theElectricUtilitiesengagedin Pueblo Units5and6onDec.31,2013. retirement ofBenFrench,OsageandNeilSimpsonIonMarch21,2014,whileColoradoElectricretired of 2014.BlackHillsPoweralsoreceivedapprovalforincreasedratesef generating facilitylocatedinCheyenne, During 2013,BlackHillsPowerandCheyenneLightcommencedconstructiononthenew132megawattPrairie Electric Utilities Utilities Gr • • • would beconsideredinthe2015to2017renewableener denied anyadditionalwindgenerationatthistime,butindicatedthattheacquisitionofeligibleener Electric ResourcePlanhearingsheldinNovember2013. were insuf lowest costtocustomers. proposal werereviewedbyanindependentevaluatorwhoverifiedthatourPowerGenerationsegment'sbidwasthe acquisition ofupto30megawattswindener On Oct.16,2013,theCPUCdeniedColoradoElectric'sapplicationforapprovalofawindsolicitation the CPUCisexpectedinfirstquarterof2014. the approvaltoconstructa40megawattgas-firedcombustionturbinereplaceretirementof issued itsinitialwrittendecisionapprovingasettlementwithColoradoElectriconthisresourceplan,whichincluded coal-fired resource requirementsthrough2019andseekingtodevelopownreplacementcapacityfortheretirementof On intends tofilearatecaseinSouthDakotarecoveritsinvestmentCheyennePrairie. Prairie, existinginfrastructureandincreasingoperatingcosts.Duringthefirstquarterof2014,BlackHillsPoweralso 2014, withthe the constructionofCheyennePrairieandanincreaseinoperatingcosts.BlackHillsPowerfiledaratecaseonJan.17, WPSC requestingelectricandnaturalgasrevenueincreasesof$13million$1.3million,respectively Power costs relatedtoserving Black HillsPowertoearnandcollectarateofreturnduringtheconstructionperiodonportionfinancing Similar totheconstructionfinancingriderapprovedby power plantandtoretiretheagingnaturalgas-firedsteamturbines,PuebloUnits#5#6. oup April 30,2013,ColoradoElectricfiledarevisedResourcePlanwiththeCPUCaddressingitsprojected ’ s SouthDakotacustomersef W ficient forallofthebidsandstateditspreferencetoconsiderrenewableener .N. ClarkpowerplanttocomplywithColoradoClean WPSC requestinganelectricrevenueincreaseof$2.8milliontorecoverinvestmentinCheyenne W The CPUCfoundthatthecalculatedcustomerbenefitsover20yearevaluationperiod yoming customers,theSDPUCapprovedaconstructionfinancingriderforBlackHills forts torestorepoweritscustomers.InJanuary2014,approval wasreceivedandthese , S.D.,experiencedthesecondmostsevereblizzardinhistorywhichleftBlack W yo. andconstructionisonscheduleforcommercialoperationsinthefourthquarter , CheyenneLight’ fective April 1,2013.OnDec.2,2013,CheyenneLightfiledaratecasewiththe gy foritselectricsystem. s gasutilitywilllookforopportunitiestopurchaselocal 74 gy plantobefiledinMay2014. The settlementapprovedbytheCPUConJan.6,2014, WPSC ef fective June16,2013.Preparationcontinuedforthe , materialsandsupplies,equipmentoutside Air –CleanJobs fective Nov This solicitationandrelatedrequestsfor . 1,2012,forCheyenneLightand Act. OnJan.6,2014,theCPUC gy needsinColoradoElectric's A finalwrittenorderfrom W .N. Clarkand gy resources W .N. Clark , torecover FORM 10K 10K | 75 gency 1, the e continue to W filiate electric After drilling and e plan to continue e recently extended W W yoming permit approval yoming will provide yoming will provide W fering in November 2013 at -heat content coal. W yoming also entered into an yoming also entered W e acquired five small gas systems five small gas systems e acquired , we continue to look for opportunities to look for opportunities , we continue W ith the termination of these swaps, our W , in 2014 to develop this stock pile. The program continued in 2013 with the drilling of two As part of the sale, Black Hills As part of the sale, This sale is subject to FERC approval. This sale is subject 75 A. As part of our growth strategy As part of . , Black Hills Power gy PP gy and capacity needs. e executed a 10-year $525 million notes of W , the termination of this contract had a positive impact on earnings since the , the termination of this contract had a positive August 2014. forts into 2014 to develop attractive oil and gas investment opportunities. As a result of these financing transactions, we expect our interest expense to decrease As a result of these financing transactions, we expect our interest expense to decrease s and Fitch. 1. However , Moody’ s mission was to prove up the value of our existing properties, primarily our Mancos formation s mission was to prove up the value of our existing properties, primarily our Mancos e will continue our ef f-site sales have been to consumers within a close proximity to our mine. f-site sales have been to consumers within oup with Cheyenne Light in with Cheyenne Light W A e continually monitor our investments and costs of operations in all states to determine when states to determine of operations in all and costs monitor our investments e continually otal annual production is estimated to be approximately 4.2 million tons for 2014, which is consistent otal annual production is estimated to be yoming completed the early redemption of high cost project financing along with the settlement of the financing along with the settlement of early redemption of high cost project yoming completed the W f-site sales contracts served by truck. In January 2014, we received State of f-site sales contracts served by truck. In T W . Coal will be sold to the power plant operator Annual production decreased in 2012 primarily due to the termination of the PacifiCorp Dave Johnston power plant Annual production decreased in 2012 primarily egulated Energy Gr eather returned to more normal patterns in the beginning of 2013 but ended colder than normal. Our Gas Utilities continued continued Utilities Our Gas than normal. colder but ended of 2013 beginning in the patterns to more normal returned eather W infrastructure and advanced metering technology such as network and related gas distribution on investment in our their focus terminals. mobile data Gas Utilities additional rate cases or other rate filings will be necessary rate cases or other additional to purchase municipal and privately-owned gas infrastructure and distribution systems. and distribution gas infrastructure municipal and privately-owned to purchase related interest rate swaps, which will reduce interest expense in future years. Black Hills swaps, which will reduce interest expense related interest rate Non-r In 2013, Black Hills during 2013 with a total of approximately 900 customers. with a total of approximately during 2013 Power Generation agreement to sell its 40 megawatt CTII natural gas-fired generating unit to the City of Gillette for approximately $22 million, unit to the City of Gillette for 40 megawatt CTII natural gas-fired generating agreement to sell its PP upon expiration of the Production from the Coal Mining segment primarily serves mine-mouth generation plants and select regional customers with primarily serves mine-mouth generation plants and select regional customers Production from the Coal Mining segment long-term fuel needs. supply coal production to on-site, mine-mouth generation facilities under long-term Our strategy is to sell the majority of our contracts. Historically our of services to the City of Gillette through an economy ener services to the City for our af resources, both new and existing, to bid on the construction of generation evaluating opportunities for their ener utilities and other regional electric utilities Coal Mining the our costs during the latter periods of the agreement. In the second quarter of 2012, pricing of this contract did not recover ratios, a revised mine plan. Mining operations moved to an area with lower overburden coal mine commenced operations under which reduced mining costs in 2013. contract which expired at the end of 201 with 2013. During much of 2013, BHEP’ two smaller volume of tons of coal near the mine mouth power plants to ensure adequate back up emer for a stock pile of approximately 75,000 coal supply coal despite limitations inherent to transporting our lower pursue new opportunities to market our Oil and Gas and strictly controlling costs. shale gas assets in the Piceance and San Juan Basins, while conserving capital well in the San Juan Basin in 201 completing two exploration wells in the southern Piceance Basin and one exploration appraisal program was deferred in 2012 due to low natural gas prices. additional Piceance wells. Our consolidated interest expense decreased in 2013, primarily due to the repayment of debt in 2012 as well as upgrades to our Our consolidated interest expense decreased in 2013, primarily due to the repayment corporate credit ratings by S&P Corporate Our new financing allowed for the termination of the de-designated interest rate swaps, which did not qualify for “hedge Our new financing allowed for the termination of the de-designated interest rate accounting” treatment provided by accounting standards for derivatives and hedges. an interest rate of 4.25 percent, which we used to repay higher cost debt and settle interest rate swaps. Our interest expense was an interest rate of 4.25 percent, which we used to repay higher cost debt and settle senior unsecured notes due in 2014, and the unfavorably impacted in 2013 by costs related to early retirement of $250 million settlement of various interest rate swaps. further in 2014. income statement will no longer reflect the volatility associated with fluctuations in the fair value of these swaps as interest income statement will no longer reflect the volatility associated with fluctuations rates change. , to recover .N. Clark W gy resources .N. Clark and .N. Clark W final written order from A gy needs in Colorado Electric's Act. On Jan. 6, 2014, the CPUC . 1, 2012, for Cheyenne Light and . 1, 2012, for Cheyenne This solicitation and related requests for This solicitation and related requests for fective Nov Air – Clean Jobs , materials and supplies, equipment and outside fective June 16, 2013. Preparation continued for the continued for 16, 2013. Preparation fective June WPSC ef The settlement approved by the CPUC on Jan. 6, 2014, The settlement approved by the CPUC gy plan to be filed in May 2014. 74 s gas utility will look for opportunities to purchase local gas gy for its electric system. April 1, 2013. On Dec. 2, 2013, Cheyenne Light filed a rate case with the 2, 2013, Cheyenne Light filed a rate April 1, 2013. On Dec. fective , Cheyenne Light’ yo. and construction is on schedule for commercial operations in the fourth quarter operations in the for commercial is on schedule yo. and construction W , S.D., experienced the second most severe blizzard in history which left most Black , S.D., experienced the second most severe blizzard in history which left most forts to restore power to its customers. In January 2014, approval was received and these forts to restore power to its customers. In January 2014, approval was received yoming customers, the SDPUC approved a construction financing rider for Black Hills the SDPUC approved a construction financing yoming customers, The CPUC found that the calculated customer benefits over the 20 year evaluation period The CPUC found that the calculated customer W WPSC requesting an electric revenue increase of $2.8 million to recover investment in Cheyenne WPSC requesting an electric revenue increase .N. Clark power plant to comply with Colorado Clean .N. Clark power plant to comply with Colorado ficient for all of the bids and stated its preference to consider renewable ener ficient for all of the bids and stated its preference W s South Dakota customers ef s South Dakota customers ’ April 30, 2013, Colorado Electric filed a revised Electric Resource Plan with the CPUC addressing its projected April 30, 2013, Colorado Electric filed oup Similar to the construction financing rider approved by the financing rider approved by the Similar to the construction gas-fired steam turbines, Pueblo Units #5 and #6. power plant and to retire the aging natural Black Hills Power to earn and collect a rate of return during the construction period on the portion of the financing the construction period on the portion earn and collect a rate of return during Black Hills Power to costs related to serving Power of $13 million and $1.3 million, respectively and natural gas revenue increases WPSC requesting electric rate case on Jan. 17, costs. Black Hills Power filed a Cheyenne Prairie and an increase in operating the construction of 2014, with the operating costs. During the first quarter of 2014, Black Hills Power also Prairie, existing infrastructure and increasing to recover its investment in Cheyenne Prairie. intends to file a rate case in South Dakota On seeking to develop and own replacement capacity for the retirement of the resource requirements through 2019 and coal-fired a settlement with Colorado Electric on this resource plan, which included issued its initial written decision approving gas-fired combustion turbine to replace the retirement of the the approval to construct a 40 megawatt of 2014. the CPUC is expected in the first quarter Electric's application for approval of a wind solicitation for the On Oct. 16, 2013, the CPUC denied Colorado ener acquisition of up to 30 megawatts of wind evaluator who verified that our Power Generation segment's bid was the proposal were reviewed by an independent lowest cost to customers. were insuf November 2013. Electric Resource Plan hearings held in at this time, but indicated that the acquisition of eligible ener denied any additional wind generation renewable ener would be considered in the 2015 to 2017 • • • Utilities Gr Utilities Utilities Electric Prairie 132 megawatt Cheyenne on the new commenced construction and Cheyenne Light Black Hills Power During 2013, Cheyenne, facility located in generating ef for increased rates received approval Hills Power also of 2014. Black Electric retired while Colorado I on March 21, 2014, and Neil Simpson of Ben French, Osage retirement 6 on Dec. 31, 2013. Pueblo Units 5 and Utilities engaged in the rate increase requests, the Electric resource plans and pending electric Pursuant to prior approved requests related to construction activities: following regulatory In October 2013, the City of Rapid City and widespread damage far exceeded average Hills Power customers experiencing power outages. Repairing the substantial an application to the SDPUC for approval to annual storm-related costs and in December 2013, Black Hills Power submitted defer the incremental costs of approximately $2.5 million, including labor contractors that were incurred in the ef costs are included in Regulatory assets until the next rate case filing. Similar to the Gas Utilities discussed below the pending acquisition of assets serving distribution systems and infrastructure. In January 2014, Cheyenne Light announced approximately 400 customers. 76 |10K FORM 10K (f) (e) Executive SummaryandOverview (d) (a) ______(b) (c) Net income(loss) Income (loss)fromdiscontinuedoperations,netoftax Income fromcontinuingoperations Corporate andEliminations Coal Mining Power Generation Gas Utilities Electric Utilities Income (loss)fromcontinuingoperations Inter-company eliminations Non-regulated Energy Utilities Revenue Oil andGas Non-regulated Energy Utilities the NotestoConsolidatedFinancial Statementsinthis Income (loss)fromdiscontinued operations,netoftaxincludestheactivitiesEnserco,ourEner those sameinterestrateswaps. mark-to-market gainonthosesameinterestrateswapsin Includes a renewal ofourRevolvingCreditFacility premium fortheearlyredemptionofour$225millionnotesand a $1.0millionwrite-of redemption ofour$250millionnotesandinterestexpenseonnew debt,while2012includesa 2013 includes Annual ReportonForm10-K. respectively Income (loss)fromcontinuingoperationsin our Ener Income (loss)fromcontinuingoperationsin swaps inconjunctionwiththeprepaymentofBlackHills GAAP Financial resultsofEnserco,ourEner this million Annual ReportonForm10-K. . after When preparingthisreclassification,certainindirectcorporatecosts andinter gy Marketingsegmentcouldnotbereclassifiedtodiscontinuedoperations of (b) $20 millionnon-cashafter , andaccordinglyhavebeenpresentedwithinCorporate.SeeNote -tax gainonsaleofour $7.6 millionafter (a) (c)(d)(e) -tax expenseforamake-wholepremiumandwrite-of W -tax mark-to-marketgainoncertaininterestrateswapsin gy Marketingsegment,havebeenreclassifiedasdiscontinuedoperations inaccordancewith illiston Basinassets.SeeNotes12and . 2013 includesa 2012 includesa Results ofOperations (f) W 2012 anda Annual ReportonForm10-K. yoming’ $ $ $ $ $6.6 millionafter $17 millionnon-cashafter 1,204,997 1,275,852 2013 76 (123,694 114,962 115,846 194,549 16,288 12,602 18,403 84,841 52,134 32,707 (4,212 s projectfinancingandwrite-of 6,327 $27 millionnon-cashafter (884 ) ) ) $ $ $ $ 21 oftheNotestoConsolidatedFinancialStatementsin Variance -tax expenserelatingtothesettlementofinterestrate 21 oftheConsolidatedFinancialStatementsinthis 123,950 101,968 (21,690 27,341 28,410 33,434 (5,040 (6,322 (1,983 For theYearsEndedDec.31, 5,253 6,093 4,717 (292 536 701 f ofdeferredfinancingcostsrelatingtotheearly -segment interestexpensespreviouslychar $0.6 million f ofdeferredfinancingcostsrelatingtoearly -tax ceilingtestimpairmentlossanda ) ) ) ) ) (in thousands) $ $ $ $ 1,081,047 1,173,884 $4.6 millionafter 2013, a 2012 (123,402 -tax mark-to-marketlossin 216,239 (15,808 gy Marketingsegment.SeeNote 21of 21,328 88,505 24,725 79,588 81,528 51,598 27,990 (6,977 (2,229 and 5,626 f ofdeferredfinancingcosts. $1.2 millionnon-cashafter $2.2 millionfor2012and ) ) ) ) $ $ $ $ Variance (87,868 (16,342 (48,303 (98,304 18,317 48,140 26,553 23,859 37,867 31,798 (2,272 (6,179 -tax make-whole 3,907 6,050 (508 ) ) ) ) ) ) ) $ $ $ $ 201 1,168,915 1,272,188 2011 $19 178,372 1 on (42,361 (75,099 ged to 40,365 81,860 49,730 47,691 34,169 (1,721 201 3,011 9,365 -tax (424 866 1, ) ) ) ) FORM 10K 10K | 77 - -
-tax f of 9 e -tax -tax fective WPSC The after fective June $1.0 million These riders , as measured by per share, , or $2.01 per share, non-cash after $7.6 million after $19 million , a $4.6 million after AFUDC with an ef $89 million $1.2 million -tax mark-to-market gain on certain -tax mark-to-market esulted in this segment being classified as classified segment being in this esulted , or $1.85 per share, in 2012 and includes the s project financing, and s project financing, -tax ceiling test impairment, a -tax ceiling test impairment, in lieu of traditional non-cash after e-tax basis unless otherwise indicated. Per shar unless otherwise indicated. e-tax basis oup and segment information does not include inter not include does information segment oup and yoming’ es unless otherwise noted. es unless otherwise W $82 million . Heating degree days for the full year in 2013 were WPSC to increase annual electric revenues by $2.8 million, WPSC to increase annual electric revenues WPSC requesting annual electric and natural gas revenue WPSC requesting annual electric and natural $20 million , to recover investment in Cheyenne Prairie, and existing , to recover investment in Cheyenne Prairie, 77 in 2013. esented on a pr esented on e pr ences diluted shar ences diluted $17 million non-cash after gy Marketing segment, which r which segment, gy Marketing gy Marketing segment sold in February 2012. gy Marketing segment sold in February compared to in 2013 compared , or $2.61 per share, Income from continuing operations includes a 2012 Income from continuing The filing seeks a return on equity of 10.25 percent and a capital structure The filing seeks a return on equity of 10.25 efer f of deferred financing costs relating to the early redemption of our $250 costs relating to the early redemption f of deferred financing The , the following business gr following , the the construction financing rider 16 million gin of $6.9 million $1 information r information -tax interest expense related to the early settlement of interest rate swaps and write-of related to the early settlement of interest -tax interest expense Additionally after , or $2.59 per share, in 2013 compared to The rider allows Black Hills Power to earn and collect a rate of return during the construction The rider allows Black Hills Power to earn and collect a rate of return during illiston Basin asset sale, a illiston Basin asset yoming customers, while also lowering the overall cost of the project to customers. yoming customers, while also lowering the overall cost of the project to customers. f of deferred financing costs related to our previous Revolving Credit Facility costs related to our previous Revolving f of deferred financing W W , particularly at the Gas Utilities. Our service territories reported colder winter weather , particularly at the Gas Utilities. Our service territories reported colder winter 2012 $6.6 million 15 million On Feb. 29, 2012, we sold our Ener we sold 29, 2012, On Feb. $1 The settlement agreement was confidential and certain terms were not disclosed. The settlement agreement was confidential ed to -tax write-of April 1, 2013. company eliminations and all amounts ar and all company eliminations Income from continuing operations includes a 2013 Income from continuing discontinued operations. operations. discontinued The for a similar construction financing rider in November 2012 which allowed Cheyenne Light and Black Hills Power to for a similar construction financing rider in November 2012 which allowed Cheyenne a 60 percent share of the project costs earn and collect a rate of return during the construction period on approximately related to serving resulted in an increase to gross mar Utility results for 2013 were favorably impacted by cold weather while 2012 utility results were unfavorably impacted Utility results for 2013 were favorably impacted by cold weather while 2012 utility by warm weather period on its approximately 40 percent share of the total project cost that relates to South Dakota customers, while also period on its approximately 40 percent share of the total project cost that relates Power received approval from the saving customers money over the long-term. Cheyenne Light and Black Hills date of degree days, compared to the 30-year average and the prior year higher than the same period in 2012. percent higher than weighted average norms for our Gas Utilities and 25 percent On Jan. 17, 2014, Black Hills Power filed a request with the On Jan. 17, 2014, Black Hills Power filed to recover investments made in electric infrastructure, including Cheyenne Prairie currently under construction. to recover investments made in electric filing seeks a return on equity of 10.25 percent and a capital structure of approximately 53 percent equity and 47 percent percent and a capital structure of approximately 53 percent equity and 47 percent filing seeks a return on equity of 10.25 debt. a rate case with the On Dec. 2, 2013, Cheyenne Light filed respectively increases of $12.8 million, and $1.3 million, costs. infrastructure and increasing operating of 54 percent equity and 46 percent debt. Utilities Commission approved a general rate case settlement agreement On Sept. 17, 2013, the South Dakota Public Power of $8.8 million, or 6.4 percent, in annual electric revenues ef authorizing an increase for Black Hills 16, 2013. On Sept. 17, 2013, the SDPUC approved Compar • • • • • Highlights of the Utilities Group include the following: Highlights of the Utilities Group include Utilities Group Income from continuing operations was continuing operations Income from in 2012. interest rate swaps, Black Hills associated with the prepayment of deferred financing costs 2013 expense for a make-whole premium and write-of expense for a make-whole expense on new debt. million notes and interest Net income was gain on sale related to the gain on sale related non-cash after million corporate notes, and a for the early redemption of our $225 tax make-whole premium on certain interest rate swaps. mark-to-market gain same items described above and losses from our Ener same items described above and losses Business Group highlights for 2013 include: 78 |10K FORM 10K Highlights oftheNon-regulatedEner Non-regulated Ener • • • • • • • • sale issubjecttoFERCapproval andcertainotherrequirementsincludedinthecontract. adjustments. of Gilletteforapproximately $22 millionanda20-yeareconomyener Black Hills leasehold inthePiceanceBasinexchangefordrillingand completingthetwowells. Basin. Our OilandGassegmentdrilledcompletedtwohorizontal wellsintheMancosShaleformationPiceance retirement date: regulations. Hills Powergeneratingfacilities,arebeingpermanentlyretiredprimarilyduetostateandfederalenvironmental On Dec.31,2013,ColoradoElectricretired annual revenueincreaseof$1.4million. On Nov size basedoneligibleinfrastructurereplacementsandthetimingoffuturegeneralratecasefilings. 2013, for$0.2million. On acquire upto30megawattsofwindener conjunction withthissameener combustion turbinetoreplace #6. OnJan.6,2014,theCPUCissueditsinitialwrittendecisionapprovingconstructionofa40megawattgas-fired replacement of requirements through2019. In estimated at$222millionofwhichapproximately$156hasbeenspenttodate. operation isexpectedinthefourthquarterof2014.Projectcostsforplantconstructionandassociatedtransmissionare will own40megawattsandBlackHillsPower55ofthecombined-cycleunit.Commercial combined-cycle, 95megawattunitthatwillbejointlyownedbyCheyenneLightandBlackHillsPower include onesimple-cycle,37megawattcombustionturbinethatwillbewhollyownedbyCheyenneLightand During 2013,CheyenneLightandBlackHillsPowercommencedconstructiononPrairie,afacilitywhichwill Pueblo Unit#6 Pueblo Unit#5 W.N. Clark Neil SimpsonI Ben French Osage territories. During2013,fivesmallgassystemswithatotal ofapproximately900customerswereacquired. Gas Utilitiescontinuedef April 2013,ColoradoElectricfiledanEner April 15,2013,theIUBapprovedaCapitalInfrastructure Plant These wellsarepartofatransactioninwhichweearnedapproximately 20,000netacresofMancosShale .25, 2013,theNPSCapprovedanInfrastructureSystemReplacementCostRecoveryChar W The af gy Group The saleisexpectedtoclose in yoming enteredintoanagreement tosellits40megawattCTIInatural-gasfiredgenerating unittotheCity W .N. Clark. fected plantsarelistedinthetablebelowwiththeiroperationssuspensiondateandultimate Black HillsPower Black HillsPower Black HillsPower Colorado Electric Colorado Electric Colorado Electric This adjustmentmechanismrequiresanannualfiling,therefore,subsequentfilingswillvaryin Total MW Company forts toacquiresmallgasdistributionsystemsadjacenttheirexistingutilityservice Additionally The resourceplanidentifieda40megawatt,simple-cycle,naturalgas-firedturbineasthe W gy Groupincludethefollowing: gy resourceplan,theCPUCdeniedColoradoElectric’ .N. ClarkandapprovingtheCPCNtoclosureofPuebloUnit#5#6.In , aCPCNwassubmittedrecommendingtheretirementofPuebloUnit#5and gy Megawatts . W August 2014upontheexpiration ofanexistingpowersaleagreement. 152.3 gy ResourcePlanwiththeCPUCaddressingitsprojectedresource .N. ClarkandPuebloUnits#5#6. 20.0 42.0 21.8 25.0 34.5 9.0 78 Type of Plant Coal Coal Coal Coal Gas Gas Automatic Dec. 31,2012 Aug. 31,2012 Oct. 1,2010 Dec. 31,2012 Dec. 31,2012 Suspended gy powerpurchaseagreement, subjecttoclosing Adjustment Mechanismef Date NA Planned orActual Retirement Date These facilities,andcertainBlack s applicationforapprovalto March 21,2014 March 21,2014 March 21,2014 Dec. 31,2013 Dec. 31,2013 Dec. 31,2013 ge thatprovidedforan fective . CheyenneLight Age ofPlant (in years) April 25, 57 43 52 64 63 71 The FORM 10K 10K | 79 e W . Financial completed in 2013 was illiston Basin f the Black Hills W -tax mark-to- f of deferred 1. $228 million Consolidated $30 million They also raised our the transaction August 2012, to an area August 2012, to -tax mark-to-market gain on The -tax write-of non-cash after $40 million, or $1.01 per share, in Notes These swaps were settled in illiston Basin assets, including including Basin assets, illiston the W of segment. 2012. 21 $27 million non-cash after s upgraded our corporate credit rating to s upgraded our corporate credit rating to , or $1.24 per share, in 201 non-cash after -tax gain on sale related to the Note Marketing 2012 compared to after See gy on post-closing adjustments. $1.2 million $50 million $1.0 million Ener our $19 million 79 agreements. fering of $525 million in senior unsecured debt at 4.25 percent due in senior unsecured debt at 4.25 percent fering of $525 million Enserco, ancillary The portion of the sale amount not recognized as gain reduced the full-cost gain reduced the full-cost not recognized as of the sale amount The portion 2012 compared to of other stock $89 million, or $2.01 per share, in certain on the sale. on the sale. -tax ceiling test impairment, a and 1 Income from continuing operations includes a s raised our corporate credit rating to Baa2 from Baa3 with continued positive outlook. On s raised our corporate credit rating to Baa2 unrealized mark-to-market loss on these swaps in unrealized mark-to-market loss on these on Form 10-K for further information outstanding the $29 million The 201 raised our corporate credit rating to BBB from BBB- with a stable outlook. raised our corporate credit rating to BBB fect of reducing the depreciation, depletion and amortization rate after the sale. rate after depletion and amortization the depreciation, fect of reducing agreement 1 sold net leasehold acres, for net cash proceeds of approximately proceeds of approximately acres, for net cash and 28,000 net leasehold 73 gross wells $1.9 million 201 we Annual Report $82 million, or $1.85 per share, in purchase . 19, 2013, we completed a public debt of . 19, 2013, we completed ed to 2012, $17 million non-cash after in this . 30, 2023. Proceeds were used to redeem our $250 million, 9 percent senior unsecured notes, pay of 9 percent senior unsecured notes, pay were used to redeem our $250 million, . 30, 2023. Proceeds stock 29, yoming project financing and related interest rate swaps, settle the de-designated interest rate swaps, partially pay yoming project financing and related interest e recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of e recognized a non-cash unrealized mark-to-market a recognized a gain of recognized the ef pool and had costs in 2013. which reduced mining overburden ratios, with lower impairment loss as a a $27 million non-cash ceiling test of 2012, our Oil and Gas segment recorded In the second quarter low natural gas prices. result of continued Coal Mining commenced operations under its revised mine plan. Mining operations moved in operations moved mine plan. Mining under its revised commenced operations Coal Mining approximately approximately Nov On Nov July 24, 2013, S&P W the remainder for other corporate purposes. down our Revolving Credit Facility and On Sept. 25, 2013, Moody’ , our Oil and Gas segment sold approximately 85 percent of its 85 percent sold approximately segment Oil and Gas , our 27, 2012 On Sept. senior unsecured rating to BBB from BBB-. On May 10, 2013, Fitch Ratings raised our Issuer Default Rating to BBB On May 10, 2013, Fitch Ratings raised our Issuer Default Rating to BBB senior unsecured rating to BBB from BBB-. on Jan. 30, 2014, Moody’ from BBB- with a positive outlook. Subsequently Baa1 and changed their outlook to stable. million and $100 million term loans with a two-year term loan for $275 million On June 21, 2013, we replaced our $150 LIBOR. at an interest rate of 1.125 percent over W compared to a November 2013. The 2012 Income from continuing operations includes a Compar Feb. 1. • • • • • • • financing costs related to our previous Revolving Credit Facility and a certain interest rate swaps. Net income was 201 asset sale, a market loss on certain interest rate swaps. Business Group highlights for 2012 include: Income from continuing operations was On 2012 Discontinued Operations through Statements Activities at Corporate include the following: Activities at Corporate Corporate
80 |10K FORM 10K Highlights oftheUtilitiesGroupincludefollowing: Utilities Group • • • • • • • • • retrofit. gas-fired facilitiestotaling152 megawattsprimarilyduetostateandfederalenvironmental regulationsandcostto Black HillsPowerandColorado Electricannouncedplanstosuspendplantoperationsat sixoldercoal-firedandnatural project. W rate ofreturnduringtheconstructionperiodonapproximately a60percentshareoftheprojectcostsrelatedtoserving Cheyenne Prairieinlieuoftraditional Cheyenne LightandBlackHillsPowerreceivedapprovalfromthe generation facilityandrelatedgaselectrictransmissioninCheyenne, the CPCNauthorizingconstruction,operationandmaintenancefornew132megawattnaturalgas-firedelectric Cheyenne LightandBlackHillsPowerreceivedfinalapprovalspermitsforPrairie. normal, weather the sameperiodin201 compared tocolderthannormalweatherduringthesameperiodin201 Heating degreedaysyear reported warmerwinterweather 2012 utilityresultswereunfavorablyimpactedbywarmweather settlement includesareturnonequityof9.6percentandcapitalstructure50debt. rate casesettlement. investments andincreasedoperationmaintenanceexpenses. On June4,2012,ColoradoGasfiledarequestwiththeCPUCforanincreaseinannualgasrevenuestorecovercapital debt forCheyenneLight.Newrateswereef annual naturalgasrevenuewitharateofreturn9.6percentandcapitalstructure54equity46 On June18,2012,the an additional$36millioningrossmar started servingutilitycustomersonJan.1,2012.Newratesandcostadjustmentswereef Colorado Electric’ rate increasesin2012thatwerenotef implemented inthreeutilityjurisdictionsduring2012.Consequently Our returnoninvestmentsmadeintheUtilitiesGroupwaspositivelyimpactedbynewandinterimratestarif approval notificationfromthe UnitedStates to purchasetheremaining50 percentwindener million andbeganservingColoradoElectriccustomerson Oct.16,2012.ColoradoElectricenteredintoa25-yearREP Colorado’ Colorado Electriccompletedconstructionofthe29megawatt BuschRanchwindprojectaspartofitsplantomeet 1, 2013,subjecttorefund. financing riderinSouthDakota.OnJan.17,2013,theSDPUC approvedastipulationwithinterimratesef 2012, resultinginanincreasetogrossmar yoming customers,whilealsoloweringtheoverallcostof the projecttocustomers.
Utility Colorado Electric Colorado Gas Cheyenne Light s RenewableEner -related demandwastemperedbylowerhumidityin2012than201 s $230million,180megawattpowerplantnearPueblo,Colo.begancommercialoperationsand The CPUCapproveda$0.2millionrevenueincreasewithnewratesef WPSC approveda$2.7millionincreaseinannualelectricrevenueand$1.6 1 forourGasUtilities.ForElectricUtilities,althoughsummertemperatureswereabove -to-date were gy Standard.ColoradoElectric’ , asmeasuredbydegreedays,comparedtothe30-yearaverageandprioryear gins atColoradoElectricfortheyearendedDec.31,2012. AFUDC. 13percentlowerthanweightedaveragenormsforourGasUtilities. fect inthepriorperiods(dollarsmillions): Colo. Colo. Wyo. State gin of$0.2millionin2012.BlackHillsPowerfiledforasimilar construction fective July1,2012. T reasury foranawardlettergrant of$8.4millionforoursharethewind gy producedbytheproject.On Jan.30,2013,ColoradoElectricreceived This allowsCheyenneLightandBlackHillsPowertoearn andcollecta 80 s 50percentshareofthisprojectcostapproximately$25 Effective Date , particularlyattheGasUtilities.Ourserviceterritories The filingwasrequiredbytheCPUCaspartofa2008 12/2012 7/2012 1/2012 WPSC touseaconstructionfinancingriderfor , year 1, heatingdegreedayswere14percentlowerthan W -to-date revenueswerepositivelyimpactedfor yo. 1 inourserviceterritories. $ $ This riderwasef Annual Revenue fective Jan.1,2012,providing Increase fective Dec.10,2012. 28.0 32.5 The 4.3 0.2 fective Nov WPSC approved fective When fs . April The . 1, A
FORM 10K 10K | 81 completed in 2012 transaction post-closing the was on over LIBOR. e recognized a e recognized August 2012, to The facility from W . $1.9 million sale of transaction information 1.1 percent date The Feb. 1, 2017. with Colorado Electric was with Colorado Electric the A $228 million further at illiston Basin assets, including assets, including illiston Basin for W 1. The 200 megawatt project cost The 200 megawatt project segment. 21 201 proceeds Note cash See Marketing Net gy to serve a 20-year PP Annual Report on Form 10-K. term loan at an interest rate of Ener in this our adjustments. 81 e-tax basis unless otherwise indicated. agreements. Revolving Credit Facility expiring $150 million Enserco, ancillary of post-closing $500 million other esented on a pr final stock e pr to Financial Statements certain The portion of the sale amount not recognized as gain reduced the full-cost pool and had pool and had gain reduced the full-cost not recognized as of the sale amount The portion gy Group include the following: gy Group and subject . , unrealized mark-to-market loss on these swaps in unrealized mark-to-market loss on these outstanding . the All amounts ar million on the sale. on the sale. agreement sold net leasehold acres, for net cash proceeds of acres, for net cash and 28,000 net leasehold 73 gross wells $261 million $42 million $165 gy Group we $750 million purchase 2012, in our Notes to Consolidated fect of reducing the depreciation, depletion and amortization rate. depletion and amortization the depreciation, fect of reducing stock 29, e recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of e recognized a non-cash unrealized mark-to-market a approximately approximately On Feb. 1, 2012, we entered into a new On June 24, 2012, we extended for one year our On June 24, 2012, we extended for one gain of $29 million costs in 2013. ratios, which reduced mining an area with lower overburden impairment loss as a a $27 million non-cash ceiling test of 2012, our Oil and Gas segment recorded In the second quarter low natural gas prices. result of continued IPP generation at Black Hills Colorado Construction of gas-fired on Jan. 1, 2012. was placed into commercial operations completed and the plant approximately us, with the consent of the administrative agent, to increase the capacity of the contains an accordion feature allowing facility to million senior unsecured, 6.5 percent notes scheduled to mature on May 15, On Oct. 31, 2012, we redeemed our $225 2013. W the ef in plan in 2012. Mining operations moved operations under its revised mine Coal Mining commenced , our Oil and Gas segment sold approximately 85 percent of its approximately 85 Gas segment sold , our Oil and On Sept. 27, 2012 compared to a approximately Feb. • • • • • • • • discussion of operating results from our business segments follows. A were adjustments Operating Results On Discontinued Operations through Activities at Corporate include the following: Corporate Non-Regulated Ener Non-Regulated Highlights of the Non-regulated Ener of the Non-regulated Highlights 82 |10K FORM 10K Operating resultsfortheyearsendedDec.31ElectricUtilitieswereasfollows(inthousands): Electric Utilities intended toreplaceoperatingincomeasdeterminedinaccordancewithGAAP Our grossmar impact totalgrossmar and otherfuelsupplycosts.However operating revenueslesscostofgassold.Ourgrossmar operating revenuelesscostoffuel,purchasedpowerandgassold.Grossmar the measure. GAAP that areincludedin(orexcludedfrom)themostdirectlycomparablemeasurecalculatedandpresentedaccordancewith numerical measureofacompany’ measure, grossmar The followingdiscussionincludesfinancialinformationpreparedinaccordancewithGAAP Non-GAAP Utilities Gr In ourManagementDiscussionand performance. Income taxexpense Other income,net Interest expense,net Operating income Depreciation andamortization Gain onsaleofoperatingasset Operations andmaintenance Gross margin-CheyenneLightgas Gross margin-electric Purchased gas-CheyenneLight Fuel andpurchasedpower-electric Revenue -CheyenneLightgas Revenue -electric Income fromcontinuingoperations Total operatingexpenses Total grossmargin Total fuelandpurchasedpower Total revenue . Grossmar FinancialMeasure oup The presentationofgrossmar gin measuremaynotbecomparabletoothercompanies’ gin (revenuelesscostofsales)isanon-GAAP gin, thatisconsidereda“non-GAAP gin ifthecostscannotbepassedthroughtoourcustomers. s financialperformance,positionorcashflowsthatexcludes(orincludes)amounts Analysis ofResultsOperations,Grossmar , whilethesefluctuatingcostsimpactgrossmar gin isintendedtosupplementinvestors’ $ $ 2013 133,595 237,665 159,961 371,260 353,082 294,048 274,963 665,308 628,045 (25,834 (56,260 77,704 18,178 19,085 37,263 52,134 gin isimpactedbythefluctuationsinpowerpurchasesandnaturalgas 633 financialmeasure.”Generally — ) ) $ $ 82 Variance financialmeasureduetotheexclusionofdepreciationfrom 15,894 13,434 17,768 14,582 20,574 17,921 38,342 32,503 (5,219 1,874 2,460 3,186 2,653 5,839 4,430 grossmar (549 536 — ) ) $ $ asanindicatorofoperatingperformance. gin measure.Furthermore,thismeasureisnot gin forourElectricUtilitiesiscalculatedas 2012 understandingofouroperating 131,721 221,771 146,527 353,492 338,500 273,474 257,042 626,966 595,542 gin forourGasUtilitiesiscalculatedas gin asapercentageofrevenue,theyonly (51,041 (30,264 75,244 14,992 16,432 31,424 51,598 , anon-GAAP 1,182 — , aswellanotherfinancial ) ) $ $ Variance financialmeasureisa (36,878 (31,312 (12,065 22,264 27,249 22,769 49,513 49,341 12,635 18,029 (5,566 (5,394 (6,993 3,712 3,907 701 768 172 ) ) ) ) ) ) $ $ 2011 109,457 194,522 142,815 303,979 289,159 310,352 288,354 614,331 577,513 (38,976 (23,271 52,475 14,820 21,998 36,818 47,691 (768 481 ) ) ) FORM 10K 10K | 83 2011 Prior year 91.3% 96.4% 93.1% Adjustment gins by $5.9 2012 90.8% 96.9% 93.9% and employee costs.
The gain was eliminated in the . increased base electric mar increased base electric 2013 96.7% 96.5% 96.6% . fset by a $2.1 million reduction of major fset by a $2.1 million reduction of major fset by a $2.1 million construction savings fset by a $2.1 million TCA, a $4.4 million increase from wholesale and TCA, a $4.4 million increase from wholesale vegetation management 83 1. These are partially of
AFUDC. 1 reflects a major overhaul and an unplanned outage at the Neil Simpson II plant and and an unplanned outage at the Neil Simpson 1 reflects a major overhaul and a $2.2 million increase at our gas utility due to an increase in volumes at our gas utility due to an increase and a $2.2 million increase primarily due to a higher asset base associated with the new 180 megawatt generating primarily due to a higher asset base associated with the new 180 megawatt generating primarily due to a higher asset base. 1 relates to the sale of assets to a related party ygen II. 201 fset by a decrease of $1.5 million from the expiration of a reserve capacity agreement fset by a decrease of $1.5 million from fective tax rate increased primarily due to an unfavorable true up adjustment in 2012, fective tax rate increased primarily due to an unfavorable true up adjustment in fective tax rate decreased primarily due to an unfavorable income tax true-up adjustment fective tax rate decreased primarily due W in 201 primarily due to debt associated with financing of the new 180 megawatt generating facility for primarily due to debt associated with financing of the new 180 megawatt generating primarily due to lower increased increased . The ef The ef : : yodak plant. primarily due to the costs associated with operating the new 180 megawatt generating increased primarily due to the costs associated with primarily due to property taxes, increased primarily due to property was comparable to the same period in the prior year gins by $9.4 million, W , partially of primarily due to a $36 million increase related to rate adjustments that include a return on significant primarily due to a $36 million increase primarily due to a return on additional investments which primarily due to a return 1 increased increased (a)
201 2012 gins from increased pricing, a $2.1 million construction savings incentive related to the new 180 megawatt gins from increased pricing, a $2.1 million gin increased gin increased gy from Colorado IPP , increased rider mar Compared to Total availability Compared to 2012 reflects a planned overhaul at 2012 reflects a planned the PacifiCorp-operated the PacifiCorp-operated Coal-fired plants Coal-fired Other plants Regulated power plant fleet availability: plant fleet power Regulated Other income (expense), net Income tax benefit (expense) facility in Pueblo, Colo., and the capital lease assets associated with the 200 megawatt generating facility providing capacity facility in Pueblo, Colo., and the capital lease assets associated with the 200 megawatt and ener Interest expense, net which interest was capitalized during construction in 201 Depreciation and amortization Gain on sale of operating assets million increase in heating degree days. driven by a 17 percent maintenance accruals related to plant suspensions and retirements. included a $2.1 million reduction of major transmission mar million increase from an Environmental Improvement Cost Recovery generating facility in Pueblo, Colo., a $1.6 rider at Black Hills Power Operations and maintenance corporate allocations, partially of facility in Pueblo, Colo. including increased plants announced for retirement and cost reduction initiatives. maintenance accruals related to the power consolidation. for tax purposes and the flow-through treatment while the prior year reflected an increased benefit for a repairs deduction taken of such tax benefit. 2012 Gross mar a $3.5 million increase from the capital investments at Colorado Electric, Income tax benefit (expense) Interest expense, net with PacifiCorp. Depreciation and amortization Operations and maintenance Gross mar 2013 to $0.7 million received in 2013. Colorado Electric in 2012 compared incentive received by that impacted 2012. ______(a) 84 |10K FORM 10K benefited 2012. Income tax Interest expense,net Depreciation andamortization increased revenue. Operations andmaintenance due toadditionalcapitalinvestments, increase inheatingdegreedays. Gross mar 2013 Operating resultsfortheyearsendedDec.31GasUtilitieswereasfollows(inthousands): Gas Utilities Income fromcontinuingoperations Income taxexpense Other expense(income),net Interest expense,net Operating income Depreciation andamortization Gain onsaleofoperatingassets Operations andmaintenance Gross margin: Cost ofnaturalgassold: Revenue: Other non-regulated Natural gas-regulated Other -non-regulated Natural gas-regulated Other -non-regulated Natural gas-regulated Comparedto Total operatingexpenses Total grossmargin Total costofnaturalgassold Total revenue gin increased : The ef
fective taxratefor2013increased primarilyasaresultoffavorableflow-throughtaxadjustment that 2012 wascomparabletothesameperiod intheprioryear primarilyduetoa$12millionincreaseresultingfromhigher retailvolumesdrivenbya25percent increasedprimarilyduetoemployeecosts,propertytaxesand increased
T ransport mar and$1.3millionofadditionalmar primarilyduetoahigherassetbase. $ $ gins increased$2.9million,surchar 2013 152,454 126,073 229,226 214,830 310,463 295,425 539,689 510,255 (19,747 (24,258 32,707 76,772 26,381 14,396 15,038 29,434 (60 — ) ) ) $ $ 84 Variance 10,593 20,494 20,824 65,114 64,163 85,608 84,987 (5,434 4,717 9,901 1,218 8,683 (330 (165 (277 gin wasattributedtoyearovercustomergrowth. 951 621 . — ) ) ) ) $ $ ge revenueincreased$1.9millionprimarily 2012 142,553 117,390 208,732 194,006 245,349 231,262 454,081 425,268 (14,313 (23,981 14,726 27,990 66,179 25,163 14,087 28,813 105 — uncollectible accountsattributedto ) ) $ $ Variance (100,503 (101,704 (10,157 (13,891 (15,709 (86,612 (85,995 (6,179 (3,734 (4,590 1,818 1,201 2,095 1,995 (617 (112 856 — ) ) ) ) ) ) ) ) ) ) ) ) $ $ 2011 146,287 121,980 222,623 209,715 331,961 317,257 554,584 526,972 (16,408 (25,976 34,169 12,908 76,336 24,307 14,704 27,612 217 —
) ) FORM 10K 10K | 85 ) ) 3,011 1,094 4,199 (1,644 (7,374 31,672 16,538 20,737 10,935 2011 2011 99.0% 98.4% 100.0% $ $ Also, $6.8 Also, $6.8 ) ) ) 400 (7,077 (1,087 (7,383 18,317 47,717 13,453 33,864 13,853 fset by increased fset by increased 2012 99.4% 99.4% 99.6% Variance $ $ 1 had been recorded in 1 had been ) ) 7 -company debt and associated -company debt and 4,599 (8,721 21,328 79,389 29,991 44,799 34,590 (14,757 2012 2013 97.9% 99.0% 94.5% $ $ ) ) ) ) (6 195 492 687 3,648 2,961 (5,040 (2,359 (5,636 gin, while these costs in 201 gin, while 1 had been recorded in operations and maintenance were 1 had been recorded Variance . 85 . $ $ ) ) 1 5,091 16,288 83,037 30,186 47,760 35,277 (11,080 (20,393 2013 $ $ fective tax rate increased as a result of an unfavorable state tax true-up adjustment in 2012. fective tax rate increased as a result of gin in 2012. primarily due to lower interest rates and a decrease in inter primarily due to lower was comparable to the prior year was comparable to The ef : primarily due to a reduction in bad debt expense, partially of in bad debt expense, due to a reduction primarily decreased was comparable to the prior year was comparable to Also, $6.8 million of costs that in 201 Also, $6.8 million of oup primarily due to an $8.7 million impact from milder weather compared to the same period in the prior to the same period weather compared impact from milder due to an $8.7 million primarily 1 1 period was favorably impacted as a result of federal research and development credits and a flow- 1 period was favorably impacted as a result (a) decreased 201 , the 201 gin decreased Total Generation ygen I experienced a planned outage in 2013. egulated Energy Gr Compared to Compared W . Heating degree days in 2012 were 14 percent lower than the prior year and 13 percent lower than normal. lower than normal. and 13 percent than the prior year were 14 percent lower degree days in 2012 . Heating Gas-fired plants Coal-fired plants Total operating expenses Income from continuing operations Other income (expense), net Income tax expense Contracted fleet plant availability: Revenue Operations and maintenance Depreciation and amortization Operating income Interest expense, net ______(a) Our Power Generation segment operating results for the years ended Dec. 31 were as follows (in thousands): Our Power Generation segment operating Non-r Power Income tax benefit (expense) Other income (expense), net Other income (expense), Interest expense, net compensation and benefits. compensation and benefits. of gross mar recorded as a reduction Depreciation and amortization expenses. Additionally through tax adjustment at Iowa Gas. Operations and maintenance Operations Gross mar year 2012 million of costs in 2012 were recorded as a reduction of gross mar recorded as a reduction costs in 2012 were million of operations and maintenance. operations 86 |10K FORM 10K and developmenttaxcredits. Income taxexpense facilities in201 Other income(expense),net which wascapitalizedduringconstructionin201 Interest expense,net for thefacilityisrecordedatColoradoElectricsegmentreportingpurposes. supply capacityandener Depreciation andamortization Pueblo, Colo.,whichbeganservingcustomersonJan.1,2012. Operations andmaintenance Colo., whichbeganservingcustomersonJan.1,2012. Revenue increased 2012 Income taxexpense lower inter Black Hills Interest expense,net recorded atColoradoElectricforsegmentreportingpurposes. Colo. isaccountedforasacapitalleaseunderGAAP; Depreciation andamortization Black HillsColoradoIPP Operations andmaintenance million relatedtoincreasedvolumesandpricingforof Revenue increased 2013 Comparedto Comparedto -company debt. W yoming’ 1. duetothecommencementofcommercialoperationournew200megawattgeneratingfacilityinPueblo, primarilydueto$2.1millionrelatingincreasedmegawatthoursdeliveredathigherprices, 201 2012 : : increased increased The ef The ef s projectfinancing 1 gy toColoradoElectricisaccountedforasacapitalleaseunderGAAP;such,depreciationexpense . fective taxratein2012wasfavorablyimpactedbyastatetrue-upthatincludedcertainresearch fective taxratein2013 includedagainonsaleofownershipinterestinthepartnershipthatheldIdahogenerating increasedprimarilyduetothecostsoperateournew200megawattgeneratingfacilityin increasedprimarilyduetotwo werecomparabletothesameperiodinprioryear werecomparabletothesameperiodinprioryear primarilyduetointerestexpenseassociatedwiththefinancingofPueblogeneratingfacility primarilydueto anda$2.4millionwrite-of $7.7millionrelatingtothecostsettleinterestrateswapsassociatedwith 1, partiallyof increasedasaresultofanunfavorabletaxtrue-upadjustment. assuch,depreciationexpensefortheoriginalcostoffacilityis f-system salesatBlackHills W ygen 1outages,partiallyof fset bylowerinter 86 f ofrelateddeferredfinancingcosts,partially -company debt. W . . The newgeneratingfacility’ The generatingfacilitylocatedinPueblo, yoming. fset bydecreasedpropertytaxesat and$2.3 s PP fset by A to , FORM 10K 10K | 87 ) ) (424
3,888 2,192 1,891 5,692 (8,395 75,287 66,892 56,617 18,670 14,735 Our 256,170 2011 2011 $ $ (a) ) ) ) ) ) ) 424 6,050 -company notes (2,958 (1,976 (5,610 (9,114 s Dave Johnston Plant in 4,246 8,329 10,560 (19,674 (14,064 232,265 2012 Variance $ $ ) (b) (c) (85 ged on coal sold under contracts 930 2,165 2,616 5,626 55,613 42,553 13,060 57,778 4,285 3,192 212,595 2012 2013 Approximately 50 percent of our coal
$ $ ) ) ) ) ) ) ) 701 (847 (312 3,421 (1,561 (4,571 (3,034 (1,537 (1,150 Variance 87 $ $ ) ) (631 (932 1 expiration of a coal sales agreement with PacifiCorp’ 1 expiration of a coal sales agreement with 6,327 5,586 2,304 51,042 39,519 11,523 56,628 primarily due to lower depreciation on mine assets and lower depreciation 2013 fset by materials and outside services related to major maintenance projects. $ $ decreased fset by a 1 percent increase in tons sold. partially of reflects decreased interest income primarily due to a decrease in the inter partially of primarily due to mining in areas with lower overburden, resulting in decreased fuel decreased primarily due to mining in areas with lower overburden, resulting in decreased 2012 primarily due to a 9 percent decrease in the average price per ton char reduced by payment of a dividend to our parent. Total operating expenses yoming. Compared to Reduction in coal reserves were due to revisions in coal modeling based upon engineering data, changes in coal limit boundaries and Reduction in coal reserves were due to revisions current coal production. Reduction in overburden was due to relocating mining operations in the second half of 2012 to an area of the mine with lower Reduction in overburden was due to relocating overburden. W Decrease in tons of coal sold is due to the Dec. 31, 201 Decrease in tons of coal sold is due to the Dec. Operating income (loss) net Interest (expense) income, Other income, net Income tax benefit (expense) Income (loss) from continuing operations Operations and maintenance and amortization Depreciation, depletion Tons of coal sold Revenue Cubic yards of overburden moved Coal reserves at year-end The following table provides certain operating statistics for the Coal Mining segment (in thousands): The following table provides certain operating thereby decreasing our price per ton for these mining costs have trended down due to lower operations and maintenance costs, customers. production is sold under contracts that include price adjustments based on actual mining costs, including income taxes. production is sold under contracts that include price adjustments based on actual containing price adjustments, receivable, Interest (expense) income, net Depreciation, depletion and amortization Operations and maintenance costs and reduced employee costs, (c) Revenue decreased (b) 2013 of mine reclamation costs. (a) ______Coal Mining operating results for the years ended Dec. 31 were as follows (in thousands): Dec. 31 were as follows for the years ended operating results Coal Mining Coal Mining Coal 88 |10K FORM 10K Oil andGasoperatingresultsfortheyearsendedDec.31wereasfollows(inthousands): Oil andGas tax returntrue-up,while201 Income taxbenefit(expense) Other income,net dividend totheparent. Interest (expense)income,net reclamation assetretirementcosts. Depreciation, depletionandamortization and headcountreductions. expiration ofanunprofitabletrainload-outcontractonDec.31,201 Operations andmaintenance mining costincreases. Approximately 50percentofourcurrentcoalproductionissoldundercontractsthatincludepriceadjustmentsbasedonactual out contractonDec.31,201 Revenue decreased 2012 deduction reportedonthe201 in 2012wasimpactedbyafavorabletrue-upadjustmentthatprimarilydrivenanincreasedpercentagedepletion Income tax: Interest expense,net Operating income(loss) Impairment oflong-livedassets Depreciation, depletionandamortization Gain onsaleofassets Operations andmaintenance Revenue operations Income (loss)fromcontinuing Income taxbenefit(expense) Other income(expense),net Comparedto Total operatingexpenses
The ef wascomparabletothesameperiodinprioryear fective taxrateincreasedin2013asaresultoflowerpercentagedepletion.Inaddition, primarilyduetoa25percentdecreaseintonssoldasresultoftheexpirationanunprofitabletrainload- 201 1 1, partiallyof decreasedduetoreducedoverburdenmovedassociatedwithlowersalesvolumesrelatedthe 1 wasimpactedbyafavorableresearchanddevelopmentcredit. : 1 taxreturn. decreasedprimarilyduetoadecreaseininter The lowef decreased fective taxratein2012wasprimarilyduetotheimpactofpercentagedepletionanda fset byincreasedtonssoldtothe $ $ 2013 primarilyduetolowerequipmentusageanddepreciationofmine 62,135 21,770 40,365 54,884 (7,251 (4,212 3,545 (614 108 — — ) ) ) $ $ 88 Variance 1. (17,365 (26,868 (16,724 (24,188 29,129 (2,902 (6,823 (1,983 3,321 1,618 Additionally . (99 W ) ) ) ) ) ) ) ) -company notesreceivableuponpaymentofa yodak plantthatexperiencedanoutagein201 $ $ 2012 , arevisedmineplanresultedinfuelcost (29,129 79,500 26,868 38,494 43,267 79,072 (3,935 (2,229 1,927 (428 207 ) ) ) ) $ $ Variance (29,129 26,868 (3,166 2,430 2,804 1,887 1,959 (736 (508 423 276 the ef ) ) ) ) $ $ fective taxrate 2011 77,070 35,690 41,380 79,808 (5,894 (1,721 2,738 1,651 (216 1. — — ) ) ) FORM 10K 10K | 89 0.93 2.75 1.70 2.25 1.88 2.17 1.29 2.84 2.44 1.04 2.07 1.88 4.29 0.96 2.76 79.74 451,823 Total Total 8,526,420 3,674,814 2011 2011 2011 11,762,331 $ $ $ $ 21 of Notes to $ $ $ $ 1.18 1.35 0.34 0.17 0.64 0.45 0.04 1.18 1.38 0.18 0.60 0.35 3.33 0.77 2.87 83.27 Taxes Taxes 559,971 8,686,191 3,485,514 2012 2012 2012 Production Production 12,543,948 $ $ $ $ $ $ $ $ — — — — — — 2013 2012 0.46 0.19 0.39 0.56 0.25 0.31
2.69 0.79 1.83 89.34 336,140 6,983,104 3,704,639 9,529,178 2013 2013 2013 Gathering Gathering Processing illiston Basin sale in 2012. See Note Processing W Compression and Compression and $ $ $ $ $ $ $ $ 1.33 0.69 1.66 1.06 0.86 1.22 1.57 0.35 1.91 0.30 1.05 1.22 LOE LOE 89 $ $ $ $ Annual Report filed on Form 10-K. depletion rate in 2013 is primarily driven by the depletion rate in 2013 is primarily driven by (a) decreased The Net of hedge settlement gains/losses Net of hedge settlement The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the The average depletion rate per Mcfe is a function periods presented. the Consolidated Financial Statements included in this the Consolidated Financial Statements included verage Price Received verage Price Received Average Average Powder River Williston All other properties San Juan Piceance Powder River Williston All other properties San Juan Piceance Bbls of oil sold Bbls of oil gas sold Mcf of natural NGL sold Gallons of sales Mcf equivalent A Gas/Mcf Oil/Bbl NGL/gallon Depletion expense/Mcfe* Crude Oil and Natural Gas Production Natural Gas Oil and Crude The following is a summary of certain annual average operating expenses per Mcfe at Dec. 31: The following is a summary of certain ______* (a) ______The following tables provide certain operating statistics for the Oil and Gas segment: Oil and Gas for the statistics operating certain tables provide The following 90 |10K FORM 10K oil in2013, Depreciation, depletionandamortization amortization rate. amount notrecognizedasgain reducedthefull-costpoolandhadef adjustments wouldsignificantlyaltertherelationshipbetween capitalizedcostsandprovedreserves. method ofaccountingforoilandgasactivities,whichtypically doesnotallowforgainonsalerecognitionunlesssuch Gain onsaleofoperatingassets valorem taxesonreducedrevenue. Operations andmaintenance 2012, anaturalproductiondeclineinourgaswells Revenue decreased 2013 Reserves reflectSEC-definedpricingheldconstantforthelifeofreserves,asfollows: (sales) of12.5Bcfeandpositiverevisionstopreviousestimates estimate takesintoaccount production historyandcontinualreassessmentoftheviabilityundervaryingeconomicconditions. be subjecttorevisionsasaresultofnumerousfactorsincluding,butnotlimitedto,additionaldevelopmentactivity CG&A. ReservesweredeterminedusingSEC-definedproductprices.Suchreserveestimatesareinherentlyimprecise andmay Reserves arebasedonreportspreparedbyanindependentconsultingandengineeringfirm. The followingisasummaryofourprovedoilandgasreservesatDec.31: gas gatheringsystems,includingassociatedcompressionandtreatingfacilities. At theEastBlancoFieldinSanJuanBasinNewMexicoandourPiceanceassetsColorado,weownoperate partially of Well-head reserveprices NYMEX prices Total MMcfe MMcf ofnaturalgas Bbls ofoil(inthousands) All otherproperties Williston Powder River Piceance San Juan Average Comparedto fset byan7percentincreaseintheaveragepricereceived for crudeoilsold. resultingfromthesaleofour primarilyduetoa24percentdecreaseinvolumessold 2012 2013 productionofapproximately decreasedprimarilyduetolowernon-operatedwellcostsandproduction taxesandad representsthegainonsaleofour $ $ Oil decreased 89.79 96.94 W illiston Basinassetsin2012. 2013 $ $ anda19percentdecreaseinaveragepricereceivedfornatural gassold, primarilyduetoalowerproportion ofourtotalreservesbeingfromcrude Gas 3.45 3.67 $ $ 9.0 Bcfe,additionsfromextensions,discoveriesandacquisitions 90 LOE $ $ 2.5 Bcfe,primarilyduetooilandnaturalgaspricing. 1.07 1.09 1.06 0.79 1.37 0.79 W Oil fect ofreducingthedepreciation, depletionand illiston Basinassetsin2012. 85.31 94.71 asaresultofthesaleour $ $ Compression and 2012 Processing Gathering 2013 $ $ 86,713 63,190 3,921 Gas
0.23 0.35 0.76 2.24 2.76 2011 The reportswerepreparedby — — — $ $ $ $ Production 2012
W Taxes The remainderofthesale 80,683 55,985 Oil e followthefull-cost W 4,116 88.49 96.19 illiston Basinassetsin
0.70 0.49 0.27 1.55 1.29 0.11 2011 The current $ $ $ $ , evolving 2011 Total Gas 133,242 95,904 6,223 2.00 1.93 3.59 4.12 1.33 2.34 2.66 1.66
FORM 10K 10K | 91 Dec. e also The $7.1 W $3.15 per per $3.15 in 2013, illiston Basin assets. W volumes sold and a 22 volumes sold and a per barrel at the $85.36 per barrel $85.36 per barrel at the $30 million f of deferred financing costs e follow the full-cost method of illiston Basin assets along with W W The remainder of the sale amount not debt as a result of proceeds from the sale of our of proceeds from debt as a result -to-date impact from adjusting our expected 2012 -to-date impact from adjusting our expected fective tax rate in 2012. on these interest rate swaps for the year ended illiston Basin assets. W decreased per barrel, adjusted to $95.67 per barrel, $95.67 per barrel, adjusted to 91 $1.9 million fect of reducing the depreciation, depletion and amortization rate. fect of reducing the depreciation, depletion 1 was positively impacted by a research and development credit and 1 was positively impacted by a research for a make-whole premium and write-of fset by a 5 percent decrease in natural gas and NGL fset by a 5 percent decrease primarily due to the year The write-down reflected a 12-month average NYMEX price of NYMEX average a 12-month reflected The write-down The write-down reflected a 12-month average NYMEX price of The write-down reflected a 12-month average
$10 million increased . Crude oil volumes sold increased 24 percent along with a 4 percent increase in the sold increased 24 percent along with a . Crude oil volumes fective tax rate for 201 represents a write-down in the value of our natural gas and crude oil properties driven by low represents a write-down in the value of represents the gain on the sale of our represents a write-down in the value of our natural gas and crude oil properties driven by low by low driven oil properties and crude natural gas of our in the value a write-down represents primarily due to decreased debt as a result of the sale of the primarily due to decreased debt as a result The ef : Each period presented produced a pre-tax net loss that resulted in an income tax benefit. produced a pre-tax net loss that resulted : Each period presented primarily due to higher costs from non-operated wells and higher compensation and costs from non-operated wells and increased primarily due to higher 1 decreased reflects lower interest expense primarily due to interest expense reflects lower 2012 201 was comparable to the prior period. per Mcf at the wellhead, for natural gas, and $2.66 per Mcf at the wellhead, for natural gas, per Mcf at the wellhead, for natural gas, and the wellhead, for $2.66 per Mcf at This was caused by commodity price reserve revisions, as well as higher cost reserves associated with our remaining revisions, as well as higher cost reserves associated with our remaining This was caused by commodity price reserve for a make-whole premium related to the early retirement of our $225 million senior unsecured notes in 2012. for a make-whole premium related to the early retirement of our $225 million Compared to Compared to illiston Basin assets in 2012. illiston Basin fective tax rate in 2013 reflects lower percentage depletion. fective tax rate in 2013 31, 2012. related to early retirement of our $250 million senior unsecured notes and interest expenses on new debt, compared to related to early retirement of our $250 million senior unsecured notes and interest million of approximately had an unrealized, non-cash mark-to-market gain on certain interest rate swaps compared to an unrealized, non-cash mark-to-market gain of Corporate results for 2013 include costs of 2013 Other income, net Income tax (benefit) expense that support the business segments. Corporate Corporate results represent certain unallocated costs for administrative activities groups as well as allocated costs associated also includes business development activities that do not fall under the two business with discontinued operations that could not be included in discontinued operations. ef Interest expense, net lower interest rates. the benefit generated by percentage depletion had a lesser impact on the ef Corporate Impairment of long-lived assets of 2012. natural gas prices in the second quarter benefit costs. Gain on sale of operating assets Depreciation, depletion and amortization Operations and maintenance was comparable to prior year Revenue was comparable to Income tax (expense) benefit Income tax (expense) 2012 for crude oil sales, partially of average price received volumes from new wells in the Crude oil production increases reflect average price received for natural gas. percent decrease in assets on Sept. 27, 2012. prior to the sale of a majority of those Bakken shale formation reserves. rate per Mcfe on higher volumes prior to the sale of most of our Bakken activities and a higher depletion would typically does not allow for gain on sale recognition unless such adjustments accounting for oil and gas activities, which capitalized costs and proved reserves. significantly alter the relationship between pool and had the ef recognized as gain reduced the full-cost Mcf, adjusted to Interest expense, net Interest expense, natural gas prices in the second quarter of 2012. second quarter in the gas prices natural Impairment of long-lived assets long-lived of Impairment Mcf, adjusted to Mcf, adjusted for crude oil. wellhead, W wellhead, for crude oil. 92 |10K FORM 10K amount ofanyimpairmentloss. carrying amountexceedsfairvalueunderthefirststep,then thesecondstepofimpairmenttestisperformedtomeasurethe potential impairment,comparestheestimatedfairvalueof areportingunitwithitscarryingamount,includinggoodwill.Ifthe unit level.Ourreportingunitshavebeendeterminedtobe at thesubsidiarylevel. process beperformedtoanalyzewhetherornotgoodwillhas beenimpaired.Goodwillistestedforimpairmentatthereporting that indicatetheassetmightbeimpaired. W Goodwill and Significant The followingdiscussionofourcriticalaccountingestimates shouldbereadinconjunctionwithNote Committee. our reportedfinancialresults. statements willbeaf the extenttherearematerialdif reported amountsofrevenuesandexpensesduringtheperiodspresented. estimates andassumptionsaf certain estimates,judgmentsandassumptionsthatwebelievearereasonablebasedupontheinformationavailable. also areaswhichrequiremanagement’ particular transactionisspecificallydictatedbyGAAP W all unresolvedpurchasepriceadjustments. and $7.0million additional 2012, relatedtopurchasepriceadjustmentsweacceptedthroughapartialsettlementagreementwiththebuyer claims weresubstantiallyresolvedthroughabindingarbitrationdecisiondatedJan.17,2014. The buyerassertedcertainpurchasepriceadjustments,somethatweaccepted,andseveraldisputed. were approximately On Feb.29,2012,wesoldtheoutstandingstockofEnserco,ourEner Discontinued Operations consistent withaccountingfordiscontinuedoperationstheyearended Costs of$0.9million Dec. 31,201 million senior unsecurednotes,andanunrealized,non-cashmark-to-marketgainoncertaininterestrateswapsofapproximately Corporate resultsfor2012included 2012 activities consistentwithaccountingfordiscontinuedoperations. 2012 includescostsof$0.9million e performourgoodwillimpairmenttestasofNov e prepareourconsolidatedfinancialstatementsinconformitywithGAAP Comparedto comparedtoanunrealized,non-cashmark-to-marketlossof $1.1 million 1. Accounting Policies forthetwelvemonthsended 201 $165 million fected. previouslyallocatedtoourEner in2013relatedtotheclaimsassignedarbitration.Lossfromdiscontinuedoperationswas 1 W fect thereportedamountsofassetsandliabilitiesatdatefinancialstatements W e believethefollowingaccountingestimatesaremostcriticalinunderstandingandevaluating ferences betweentheseestimates,judgmentsorassumptionsandactualresults,ourfinancial e havereviewedthesecriticalaccountingestimatesandrelateddisclosureswithour , subjecttofinalpost-closingadjustments. previouslyallocatedtoourEner ” ofourNotestoConsolidatedFinancialStatementsinthis $7.1 million s judgmentinselectingamongavailableGAAP Accounting standardsfortestinggoodwillimpairment require atwo-step Dec. 31,2013and Critical foramake-wholepremiumrelatedtoearlyretirementofthe$225million . 30eachyearorupontheoccurrenceofeventschanges incircumstances gy MarketingsegmentwerereclassifiedtotheCorporate anddoesnotrequiremanagement’ Accounting Estimates 92 2012, respectively gy MarketingsegmentwerereclassifiedtotheCorporate $42 million gy Marketingsegment.Netcashproceedsatdateofsale Actual resultsmaydif Dec. 31,2012 . Inmanycases,theaccountingtreatmentofa ontheseinterestrateswapsfortheyearended The firststepofthistest,usedtoidentify . Resultsfor2013includetheresolutionof alternatives. comparedto$3.4million s judgmentinapplication. W Annual ReportonForm10-K. fer fromourestimatesandto e expensed$1.4million W e arerequiredtomake 1, “BusinessDescription The disputed , andan in201 These $0.9 million Audit There are in 1. $1.9
FORM 10K 10K | 93 illiston W . illiston Basin of W -tax gain on sale was , an increase of 0.25 percent , an increase of 0.25 ferences between the , a $19 million after , annual impairment test indicated that . 30, 2013, annual impairment Nov wo generally accepted methods of accounting for oil wo generally accepted methods of accounting T These valuations require significant judgments, require significant These valuations s sale of oil and gas properties in the The result of the income approach was sensitive to the 2 The result of the income e account for our oil and gas activities under the full cost e account for our oil and gas activities W . Because of the substantial dif , no additional write-down was required. Reserves Dec. 31, 2013, no additional write-down was required. As an illustration of this sensitivity As an illustration of The prices, as well as costs and development capital, are The prices, as well as costs and development 93 gy industries. gy industries. ged to earnings in that reporting period. Under these SEC-defined ged to earnings in that reporting period. . 30, 2013. The results of our The Company’ . 30, 2013. Activities Nov Nov , we determined that one reporting unit, Colorado Electric with one reporting unit, Colorado Electric . 30, 2013, we determined that forts and full cost. gy industries. Nov Oil and Gas These costs are amortized using a unit-of-production method based on volumes produced These costs are amortized using a unit-of-production e estimate the fair value of our reporting units using a combination of an income of an combination using a units of our reporting value the fair e estimate W This method values the reserves based upon SEC-defined prices for oil and gas as of the end This method values the reserves based The result of our valuation analysis estimates Colorado Electric's fair value at $814 million, analysis estimates Colorado Electric's The result of our valuation . in goodwill as of Dec. 31, 2013 Accounting for Any conveyances of properties, including gains or losses on abandonments of properties, are generally Any conveyances of properties, including -tax. Under the SEC-defined product prices at -tax. Under the SEC-defined product prices ferences between the properties sold and those retained, in which case capitalized costs shall be allocated on the ferences between the properties sold and those retained, in which case capitalized otal net cash proceeds from the sale were approximately $228 million. T $353 million e have and gas activities are available - successful ef and gas activities are available - successful and costs related to acquisition, exploration, development, abandonment method, whereby all productive and nonproductive reclamation activities are capitalized. and proved reserves. a ceiling properties with no gain or loss recognized. Net capitalized costs are subject to treated as adjustments to the cost of the of cost or of the present value of future net revenues of proved reserves and the lower test that limits such costs to the aggregate fair value of unproved properties. price changes. of each reporting period adjusted for contracted of were more than the full cost ceiling at June 30, 2012, which required a write-down product prices, our net capitalized costs $17 million after requirements using a 12-month average price calculated using the first- in 2013 and 2012 were determined consistent with SEC of 12 months in the reporting period held constant for the life of the properties. Because day-of-the-month price for each of the we can provide no assurance that future write-downs will not occur the fluctuations in natural gas and oil prices, in accordance with SEC Rule 4-10 of As noted, we utilize the full-cost method of accounting for our oil and gas activities generally are recorded as an adjustment Regulation S-X (Rule 4-10). Under the full-cost method, sales of oil and gas properties would significantly alter the relationship between to capitalized costs, with no gain or loss recognized, unless such adjustments the capitalized costs and proved oil and gas reserves. ng, then life of the properties. If the net capitalized costs exceed the full-cost ceili assumed to remain constant for the remaining to be char a permanent non-cash write-down is required Although an impairment did not exist as of Although an impairment including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans with long range business plans on our internal five-year cash flows, based 1) estimates of future but not limited to: including, participant our view of market as appropriate for and adjusted terminal value calculation estimated using a cash flows weighted- of an appropriate 3) the determination for our businesses, growth rates 2) estimates of long-term assumptions, for as recent sales transactions information such utilization of market rate, and 4) the of capital or discount average cost the utility and ener comparable assets within W carrying value. of all reporting units exceeded their impaired, since the estimated fair value our goodwill was not percent, which we do not exceeded its carrying value by only 18 had an estimated fair value that goodwill of $245 million, excess. consider a substantial plan financial forecast and beyond our internal five-year business flow growth rate applicable to periods percent long-term cash cost of capital assumptions. the 5.44 percent weighted-average excess of rate reduction of 0.25 percent would result in an estimated fair value in in the cost of capital combined with a growth as of carrying value of $45 million, or 7 percent, Full Cost Method of North Dakota in 2012 was significant as defined by Rule 4-10 and, accordingly compared to a carrying value of $690 million as of compared to a carrying Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining determining units and reporting of the identification including judgment, requires test impairment the goodwill of Application unit. the reporting value of the fair Accounting for oil and gas activities is subject to special, unique rules. Accounting for oil and gas activities is basis of the relative fair value of the properties in the cost center approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value fair estimates which market approach, and a cash flows, future on discounted based fair value estimates which approach, ener within the utility and comparables based on market recorded. total capitalized costs shall be allocated between Under the guidance of Rule 4-10, if a gain or loss is recognized on such a sale, amortization, unless there are substantial the reserves sold and the reserves retained on the same basis used to compute economic dif natural gas, we allocated based on Basin crude oil properties we sold and those properties retained, which were predominantly relative fair values. 94 |10K FORM 10K earnings. comprehensive income(loss)untilitisreclassifiedintoearningsinthesameperiodthathedgeditemrecognized in ef recognized currentlyinearnings.Derivativesmaybedesignatedashedgesofexpectedfuturecashflowsorfairvalues. based onthedesignationofderivative. balance sheetandtheirmeasurementatfairvalue.Ourpolicyforrecognizingthechangesinvalueofderivatives varies Accounting standardsforderivativesrequiretherecognitionofallderivativeinstrumentsaseitherassetsorliabilities onthe Derivatives Measurement In additiontotheinformationprovidedbelow Risk Management value ofourprovedreserves.Finally reserves. our capitalizedoilandgaspropertiesincorporatestheestimatedunit-of-productionattributabletoestimatesofproved statements. Forexample,sinceweusetheunit-of-productionmethodofcalculatingdepletionexpense,amortization rateof Despite theinherentimprecisioninestimatingouroilandnaturalgasreserves,estimatesareusedthroughout financial reserves. may alsochange. from actualresults.Inaddition,asoilandgaspricescostlevelschangeyearto of futureoperatingcosts,severancetaxes,developmentcostsandworkoverallwhichmayinfactvaryconsiderably available data,engineeringandgeologicalinterpretationjudgment.Forexample,wemustestimatetheamounttiming oil andnaturalgasreservesannually economic andoperatingconditions. engineering datademonstratewithreasonablecertaintytoberecoverableinfutureyearsfromknownreservoirsunderexisting Estimates ofourprovedoilandnaturalgasreservesarebasedonthequantitiesthatgeological Oil andNaturalGasReserveEstimates depletion expenserecordedwithinourconsolidatedfinancialstatements. were recordeddif the undevelopedacreagesold,wedidnotbelievethiswasanappropriatemethodologyforallocation.Ifamountofgain in ourcostcenter 4-10 andweutilizedtheratioofprovenreservequantitiesfrompropertiessoldcomparedtototalquantities substantially If adif use ofdif Pricing modelsandtheirunderlying assumptionsimpacttheamountandtimingofunrealized gainsandlossesrecorded,the as welltimevalueandyield curveorvolatilityfactorsunderlyingthepositions. and pricingmodelsthatconsidercurrentmarketcontractual pricesfortheunderlyingfinancialinstrumentsorcommodities, information, wherepossible.Ifexternalmarketpricesare not available,fairvalueisdeterminedbasedonotherrelevantfactors Fair valuesofderivativeinstrumentscontractsarebasedon activelyquotedmarketpricesorotherexternalsourcepricing payments, toafixedrate. and forinterestrateswapsweenterintotoconvertaportion ofourvariableratedebt,orassociatedinterest anticipated futureproductionatourOilandGassegment, or tofulfillthenaturalgashedgingplansforandelectricutilities non-trading (hedging)purposes.Ourtypicalhedgingtransactions relatetocontractsweenterintofixthepricereceivedfor W value changesoftheunderlyinghedgeditem. earnings. Changesinfairvalueofderivativesdesignatedashedgesarerecognizedcurrentearningsalong withfair fective portionofchangesinfairvaluesderivativesdesignatedascashflowhedgesisrecordedacomponent other e currentlyusederivativeinstruments,includingoptions,swaps, futures,forwardsandothercontractualcommitmentsfor ferent methodofallocatingthecapitalizedcostswaschosen,gainrecordedonourtransactioncouldvary The netbookvalueofouroilandgaspropertiesisalsosubjecttoa“ceiling”limitationbasedinlar ferent pricingmodelsorassumptions couldproducedif The inef . Forexample,iftheallocationwasmadeonsamebasisusedtocomputeamortizationasnotedwithinRule ,” ofourNotestoConsolidatedFinancialStatementsinthis , wewouldhaverecordedagainonsaleofapproximately$160million.Becausethevalueassociatedwith ferently Any significantvarianceintheseassumptionscouldmateriallyaf fective portionofchangesinfairvaluederivativesdesignatedascashflowhedgesisrecordedcurrent Activities , itwouldimpacttheamountofadjustmenttoourcapitalizedcoststhereforeimpactingfuture An independentpetroleumengineeringcompanypreparesreportsthatestimateourproved . , thesereservesarethebasisforoursupplementaloilandgasdisclosures. The accuracyofanyoilandnaturalgasreserveestimateisafunctionthequality The changesinfairvalueofderivativesthatarenotdesignatedashedges , seeNote 8, “RiskManagement 94 ferent financialresults. Annual ReportonForm10-K. Activities fect theestimatedquantityandvalueofour ” andNote9,“Fair , theestimateofprovedreserves V ge partonthe alue The FORM 10K 10K | 95 rust T s ferent ) The table 136 (116 Master A fect our pension and fect our pension and rusts for the funded rusts for the T rust. T and Interest Cost The determination of our The determination of ferences are the result of ferent from our estimates, the Impact on 2013 Service $ $ ) 1,914 (1,644 ferences between the financial and tax basis of Annual Report on Form 10-K, we have two defined have two 10-K, we on Form Report Annual Although we believe our assumptions are appropriate, Although we believe 95 e classify deferred tax assets and liabilities into current and non- Benefit Obligation W fect of temporary dif Impact on Dec. 31, 2013 Accumulated Postretirement $ $ ement Benefits ement etir Postr . Our assessment of our exposure to contingencies could change to the extent there are additional future . Our assessment of our exposure to contingencies The estimated discount rate used to determine annual benefit cost accruals will be 5.05 percent in 2014; the cost accruals will be 5.05 percent in rate used to determine annual benefit The estimated discount ferences in our actual experience or significant changes in our assumptions may materially af experience or significant changes in ferences in our actual axes T Change in Assumed Trend Rate Accounting for contingencies requires significant judgment regarding the estimated probabilities and ranges of exposure significant judgment regarding the estimated probabilities and ranges of exposure Accounting for contingencies requires e use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are recognized, e use the liability method of accounting for income taxes. Under the liability method, e do not pre-fund our non-qualified pension plans. One of the three postretirement benefit plans is partially funded. e do not pre-fund our non-qualified pension Increase 1% Decrease 1% period than they are reported in the financial statements. current amounts based on the nature of the related assets and liabilities. W at currently enacted income tax rates, to reflect the tax ef The Company and its subsidiaries file consolidated federal income tax returns. Each tax paying entity records income taxes as The Company and its subsidiaries file consolidated federal income tax returns. subsidiaries based on separate company if it were a separate taxpayer and consolidating adjustments are allocated to the computations of taxable income or loss. to potential liability becomes available. If actual obligations incurred are dif developments, or as more information When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the or other legal liability has been incurred, a loss is recognized when the amount When it is probable that an environmental of the probability and the amount of loss are made based on currently available loss can be reasonably estimated. Estimates facts. Income Contingencies flows. have a material impact on our financial position, results of operations and cash recognition of the actual amounts could temporary dif assets and liabilities, as well as operating loss and tax credit carryforwards. Such be reported on the income tax return in a dif provisions in the income tax law that either require or permit certain items to discount rate used in 2013 was 4.30 percent. In selecting the discount rate, we consider cash flow durations for each plan’ discount rate, we consider cash flow 2013 was 4.30 percent. In selecting the discount rate used in Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of assumptions, the most involves numerous benefit obligations postretirement for pension and other Accounting long-term rates of return value of future plan obligations; expected rate for measuring the present which relate to the discount and healthcare cost projections. of future increases in compensation levels; on plan assets; rate $8.1 million compared to $15 funded pension plan is expected to be cost for 2014 for our non-contributory The pension benefit million in 2013. W to the Consolidated Financial Statements in this in Statements Financial Consolidated Note 17 to the in As described retirement plans. and several non-qualified healthcare plans post-retirement plans, three defined benefit pension also been established. healthcare plans have the post-retirement portion of determined by benefits is dependent on the assumptions for pension and other postretirement obligation and expenses by actuaries in calculating the amounts. management and used significant dif obligations and our future expense. other postretirement curves for comparable durations. on high credit quality fixed income yield liabilities and returns Plans increase or decrease to our healthcare trend rate for our three Retiree Healthcare below shows the expected impacts of an (in thousands): Pension and Other Pension holds the assets for the Pension Plans. Each Pension Plan has an undivided interest in the Master interest in the Plan has an undivided Plans. Each Pension assets for the Pension holds the 96 |10K FORM 10K term andlong-termborrowings. As describedbelow The followingtableprovidesaninformationalsummaryofourfinancialpositionasDec.31(dollarsinthousands): maturities, anticipateddividends,andcapitalexpendituresdiscussedinthissection. equity financings,takenintheirentirety W high naturalgasprices. requirements duringpeakmonthsofthewinterheatingseasonduetohighernaturalgasconsumptionandperiods of Power Generationsegment,aswellthepaymentofdividendstoourshareholders. The mostsignificantitemsimpactingcashareourcapitalexpenditures,thepurchaseofnaturalgasforGasUtilities andour and redemptionofoutstandingdebtequitysecuritieswhenrequiredorfinanciallyappropriate. expenditures, dividends,pensionfunding,investmentsinoracquisitionsofassetsandbusinesses,paymentdebtobligations operations andsupplementedwithcorporateborrowings. BHC anditssubsidiariesrequirecashtosupportgrowourbusiness.Ourpredominantsourceofissupplied by our OVER Consolidated FinancialStatementsinthis performed todateindicatesnomaterialimpactourconsolidatedfinancialstatements.SeeNote the finalregulationsin2014.ProceduralguidanceisexpectedfromIRSearly2014tofacilitateimplementation. beginning onorafterJan.1,2014,withearlyadoptionpermitted. result theimpactshouldbetakenintoaccountinperiodofadoption.Ingeneral,suchregulationsapplytotaxyears amounts paidtoacquire,produce,orimprovetangibleproperty In addition,onSept.13,2013,theU.S. generation ofanetoperatinglossforFederalandstateincometaxpurposesin2013. Federal andstatenetoperatinglosscarryforwards.Infact,the50percentbonusdepreciationwasacontributingfactorto provisions ofthe impact ontheamountsprovidedforincometaxesincludingourabilitytorealizedeferredtaxassets. to changesintaxlaw audits couldsignificantlyimpacttheamountsprovidedforincometaxesinourconsolidatedfinancialstatements. estimates arereasonable,changesintaxlawsorourinterpretationsofandtheresolutioncurrentanyfuturetax be char that wewillbeunabletorealizeallorpartofourdeferredtaxassetsinthefuture,anadjustmentassetwould all ofthedeferredtaxassetswillnotberealizedandprovidesanynecessaryvaluationallowancesasrequired.Ifwedetermine In assessingtherealizationofdeferredtaxassets,managementconsiderswhetheritismorelikelythannotthatsomeportionor Total debtratio Long-term debtratio Ratios Stockholders’ equity Long-term debt Short-term debt,includingcurrentmaturitiesoflong-term debt Restricted cashandequivalents Cash andcashequivalents Financial PositionSummary e believethatourcashonhand,operatingflows,existingborrowingcapacityandabilitytocompletenewdebt VIEW ged toincomeintheperiodsuchdeterminationwasmade. A TRA , during2013,weissued$800 millioninlong-termdebtandrepaidapproximately$640 millioninshort- , the involvingprimarilytheextensionof50percentbonusdepreciationresultedinminimalutilization American T axpayer Relief T , providesuf reasury issuedfinalregulationsaddressingthetaxconsequencesassociatedwith Annual ReportonForm10-Kforadditionalinformation. Liquidity andCapitalResour ficient capitalresourcestofundourongoingoperatingrequirements,debt Act of2012,whichwasenactedJan.2,2013,didnothaveamaterial This cashisusedfor 96 . The regulationshavetheef W Although webelieveourassumptions,judgmentsand e expecttoimplementmost,ifnotall,oftheprovisions , amongotherthings,workingcapital,capital ces W e couldexperiencesignificantcash fect ofachangeinlawandas $ $ $ $ $ 14 inourNotesto 1,307,748 1,396,948 2013 As expected,certain 82,500 7,841 53% 52% 2 $ $ $ $ $ W 1,232,509 2012 ith respect 938,877 380,973 Analysis 15,462 7,916 52% 43% FORM 10K 10K | 97 e W $64 These $30 3 years. The mark-to-market value e paid approximately fecting cash needs will fecting cash W e have implemented risk mitigation risk mitigation e have implemented W non-cash pre-tax unrealized mark-to-market gain on non-cash pre-tax unrealized mark-to-market to settle these swaps upon repayment of the debt. Dec. 31, 2013, and Dec. 31, 2012, we recorded a 97 $1.9 million $8.5 million fects of significant changes in crude oil and natural gas commodity fects of significant changes in crude oil , the potential for unforeseen events af for unforeseen , the potential , 80 percent of our interest rate exposure has been mitigated through , 80 percent of our interest rate exposure , commodity prices, significant capital projects and acquisitions, capital projects and prices, significant , commodity e paid W . Associated Hedging Strategies Associated Hedging at Dec. 31, 2013. At Dec. 31, 2013 ficient resources to fund our cash requirements, there are many factors with the potential to the potential factors with are many there requirements, our cash to fund resources ficient $9.1 million fecting Liquidity fecting e deploy hedging strategies that include floating-to-fixed interest rate swap agreements to reduce our e deploy hedging strategies that include , Commodity Pricing and , Commodity Pricing notional amount floating-to-fixed interest rate swaps with a maximum remaining term of notional amount floating-to-fixed interest rate swaps with a maximum remaining yoming project financing debt. Af W W $75 million to settle these swaps in November 2013. For the years ended to settle these swaps in November 2013. gain and non-cash pre-tax unrealized mark-to-market get hedging approximately 50 to 70 percent of our forecasted natural gas supply using options, futures and basis swaps. natural gas supply using options, futures 50 to 70 percent of our forecasted get hedging approximately e use a price-based approach where, based on market pricing, anywhere from 0 percent to 90 percent of our existing natural on market pricing, anywhere from 0 percent to 90 percent of our existing e use a price-based approach where, based e manage liquidity needs through hedging activities, primarily in connection with seasonal needs of our utility operations in connection with seasonal needs through hedging activities, primarily e manage liquidity needs e have eather Seasonality Until November 2013, we had $250 million notional amount de-designated interest rate swaps. Until November 2013, we had $250 million tar exposure to interest rate fluctuations. either fixed or hedged interest rates. Several of our debt instruments have a variable interest rate component which can change dramatically depending on the variable interest rate component which can change dramatically depending on Several of our debt instruments have a economic climate. Interest Rates Our cash flows in our Oil and Gas segment can be subject to fluctuations in commodity prices. Significant changes in crude oil can be subject to fluctuations in commodity prices. Significant changes in Our cash flows in our Oil and Gas segment a significant impact on liquidity needs. Since commodity prices are uncontrollable, or natural gas commodity prices can have to mitigate the ef we have implemented a hedging program Oil and Gas Factors Our cash flows and in turn liquidity needs in many of our regulated jurisdictions can be subject to fluctuations in weather and regulated jurisdictions can be subject to in turn liquidity needs in many of our Our cash flows and natural gas we have implemented commission-approved weather conditions are uncontrollable, commodity prices. Since gas commodity pricing. mitigate significant changes in natural many of our regulated jurisdictions to hedging programs in Utility Factors pricing on existing production. New production is subject to market prices until the production can be quantified and hedged. is subject to market prices until the production can be quantified and pricing on existing production. New production W See using options, futures and basis swaps for a maximum term of three years forward. gas and crude oil production is hedged “Market Risk Disclosures” for hedge details. Although we believe we have suf we we believe Although Significant Factors Factors Significant influence our cash flow position, including seasonality our cash flow position, influence requirements imposed by state and federal agencies, and economic market conditions. and economic market and federal agencies, imposed by state requirements however stabilize cash flow; where possible, to programs, million million W continue to exist. continue to W movements, and commodity price movements. peaks in fuel requirements), interest rate (including seasonal these de-designated interest rate swaps, respectively W swaps have been designated as cash flow hedges, and accordingly their mark-to-market adjustments are recorded in swaps have been designated as cash flow hedges, and accordingly their mark-to-market Balance Sheets. accumulated other comprehensive income (loss) on the accompanying Consolidated of these swaps was a liability of Until November 2013, we also had interest rates swaps with a notional amount of $75 million designated as cash flow hedges Until November 2013, we also had interest rates swaps with a notional amount to our Black Hills 98 |10K FORM 10K W triggered, requireustopostcashcollateralpositionswiththe counterpartytomeettheseobligations. Under contractualagreementsandexchangerequirements, BHCoritssubsidiarieshavecollateralrequirements,whichif Cash Collateral 2017, andourabilitytoaccessthepublicprivatecapitalmarkets throughdebtandsecuritiesof Our primarysourcesofcasharegeneratedfromoperatingactivities,ourfive-yearRevolvingCreditFacilityexpiring Cash Generation CASH GENERA 10-K. See additionalinformationinNote mitigate futurerateincreasesrelatedtocapitaladditions. generally increasefuturerevenuerequirements,thebonusdepreciationassociatedwiththesecapitaladditionswillpartially benefits forBHCasindicatedinthetablebelow: generally toqualifyingpropertyplacedinserviceduring2013. property placedinserviceduring2012. Acceleration ofdepreciationfortaxpurposesincluding50percentbonuswaspreviouslyavailablecertain 20 years. The cashgeneratedbybonusdepreciationisanaccelerationoftaxbenefitsthatwewouldhaveotherwisereceivedover 15to extending thetaxlosscarryforwardsfrombeingfullyutilizeduntil2018basedoncurrentprojections. approximately $26million. service onorbeforeDec.31,2014.Itisestimatedthatthetaxbenefitsattributabletosuchqualifyingprojectswillbe In addition,bonusdepreciationappliestoqualifyingpropertywhoseconstructionbeganbefore2014,butwillbeplaced in Income W Federal Federal andStateRegulations creditors, debtholders,securedtaxingauthoritiesandguaranteeholders. obligations areef subordinate totheclaimsagainstassetsofsuchsubsidiariesbytheircreditors. shareholder toreceiveassetsofanyourdirectorindirectsubsidiariesuponasubsidiary'sliquidationreor in whichtheutilityassetsarelocated.Furthermore,asaresultofourholdingcompanystructure,rightcommon subsidiaries andtheuseofourutilityassetsascollateralgenerallyrequirepriorapprovalstateregulatorsinthe various regulationsbyourcommissionsthatcaninfluenceliquidity Interest RateSwapsDerivatives NotDesignatedasHedges Oil andGasDerivatives Natural GasFuturesandBasis SwapsPursuanttoUtilityCommissionApprovedHedging Programs Purpose ofCashCollateral e havepostedthefollowingamountsofcashcollateralwith counterpartiesatDec.31(inthousands): e arestructuredasautilityholdingcompanywhichownsseveralregulatedutilities. Total CashCollateralPositions T ax Additionally fectively subordinatedtoallexistingandfutureclaimsofthecreditorsoursubsidiaries,includingtrade TION Tax benefit (in millions) , fromaregulatoryperspective,whilethecapitaladditionsatCompany'sregulatedbusinesses AND CASHREQUIREMENTS The additionaldepreciationdeductionswillservetoreducetaxableincomeandcontribute 14 ofNotestotheConsolidatedFinancialStatementsfiledinthis The A TRA, enactedintolawonJan.2,2013,extended50percentbonusdepreciation $ 2013 98 These provisionsresultedinapproximately$273millionoftax 24 $ . As anexample,theissuanceofdebtbyourregulated 2012 Therefore, ourholdingcompanydebt 31 W ithin thisstructure,wearesubjectto $ 2011 ferings whennecessary Annual ReportonForm 218 $ $ 2013 12,624 10,123 2,501 ganization is — $ $ Feb. 1, 2012 22,083 12,930 5,960 3,193 . FORM 10K 10K | 99 . 395 e were in W , 1.375 $750 The proceeds $8.5 million $87 million Dec. 31, 2013 . Available Capacity at $ This repayment 0.375 percent . 30, 2023. 22 At our current credit rating of At our current credit Nov $64 million May 15, 2014. The interest costs associated with the The interest costs associated Dec. 31, 2013 . Letters of Credit at $ 83 , that has an accordion feature which Feb. 1, 2017, that has an accordion ferings of equity which included a make-whole provision of approximately ged on the unused amount of the Revolving Credit Facility of the Revolving Credit Facility ged on the unused amount notes originally due on . 99 Dec. 31, 2013 Borrowings at $ $261 million yoming project financing with a remaining balance of , 4.25 percent unsecured note expiring on 500 W 9.0 percent firmative and negative covenants, such as limitations on the creation of firmative and negative covenants, such Current Capacity $ commitment fee is char commitment fee is $525 million A Dec. 31, 2013. . Although these contractual restrictions exist, we do not anticipate triggering any default Although these contractual restrictions , our recourse leverage ratio is the ratio of our recourse debt, letters of credit and guarantees , our recourse leverage ratio is the ratio , for approximately , had the following borrowings, outstanding letters of credit and available Dec. 31, 2013, had the following borrowings, outstanding Expiration Feb. 1, 2017 notional de-designated interest rate swaps for approximately of the Revolving Credit Facility Dec. 9, 2016,and settle the interest rate swaps designated to this project financing of gins for base rate borrowings, Eurodollar borrowings and letters of credit are Eurodollar borrowings and letters gins for base rate borrowings, revolving corporate credit facility which matures on revolving corporate $250 million senior unsecured based on current credit ratings. based on current credit and accrued interest. ransactions $250 million . edit Facility $500 million Activities Redeem our occurred on Dec. 19, 2013 $8.5 million Repay our variable interest rate Black Hills originally due on Remainder was used for general corporate purposes. Settle the Pay down $55 million . 19, 2013, we entered into a new to 1.00. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of 0.65 to 1.00. Subject to applicable cure periods, and 1.375 percent, respectively . Borrowings are available under a base rate or various Eurodollar rate options. under a base rate or various Eurodollar . Borrowings are available • • • • • e have a Credit Facility Revolving Credit Facility Recent Financing T On Nov allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to issuing agents, to increase the capacity consent of the administrative agent and allows us, with the million based upon our credit ratings. under the agreement are determined letters of credit or borrowings BBB equivalent, the mar percent from this new debt were used to: Our principal sources for our long-term capital needs have been issuances of long-term debt securities by the Company and its Our principal sources for our long-term capital needs have been issuances of long-term subsidiaries along with proceeds obtained from public and private of W Capital Resources Revolving Cr which is 0.20 percent Our Revolving Credit Facility at capacity (in millions): customary af The Revolving Credit Facility contains not to restrictions on certain transactions, and maintaining a recourse leverage ratio new indebtedness and on certain liens, exceed ng. their remaining commitments and accelerate all principal and interest outstandi default that entitles the lenders to terminate Under the Revolving Credit Facility sum of our recourse debt, letters of credit and guarantees plus our net worth. issued to our total capital, which is the compliance with these covenants as of to, or us from paying cash dividends if a default or an event of default exists prior The Revolving Credit Facility prohibits would result after paying a dividend. measures or restrictions. Our principal sources to meet day-to-day operating cash requirements are cash from operations and our corporate Revolving and our corporate are cash from operations cash requirements day-to-day operating sources to meet Our principal Credit Facility Operating Operating DEBT 100 |10K FORM 10K interest rateenvironment: During thenextthreeyears,BHCplanstoconsidercompletingfollowingfinancingactivitiestakeadvantageoflow Future FinancingPlans interest. In May2012,BlackHillsPower million outstanding andnosharesofpreferredstockoutstanding. stock and25millionsharesofpreferredstock. statement withtheSECbeforeitexpires.Ourarticlesofincorporation authorizetheissuanceof regulatory authorities. by ourBoardofDirectors,certaincovenantsinfinancing arrangementsandrestrictionsimposedbyfederalstate shelf registrationstatementdoesnotlimitourissuancecapacity senior debtsecurities,subordinatedcommonstock,preferredwarrantsandothersecurities. W Shelf Registration three years. Based onourcurrentcapitalspendingforecast,wedonotanticipatetheneedtoaccessequitymarketsin next Equity us tobeindefault. The RevolvingCreditFacilityprohibitsusfrompayingcashdividendsifweareinadefaultorwould cause that permitstheaccelerationofdebtmaturitiesormandatoryprepayment. triggered otherdefaultprovisionsunderanydebtagreementtotalingintheaggregateprincipalamountof$35million ormore default undersuchagreementsifBHCoritsmaterialsubsidiariesfailedtomaketimelypaymentsofdebtobligations or Our RevolvingCreditFacilityand$275millioncorporatetermloancontaincross-defaultprovisionsthatcouldresult ina Cr mature on On Oct31,2012,weredeemedour under thisnewtermloanwas 2013 and$25millioninshort-termborrowingunderourRevolvingCreditFacility new termloanrepaidthe$150milliondueonJune24,2013,$100corporateSept.30, On June21,2013,weenteredintoanewtwo-year$275milliontermloanexpiringon19,2015. e haveanef oss-Default Pr • • pre-tax. Extension ofourRevolvingCreditFacilitywhichexpiresin2017. of theestimated$222millionCheyennePrairiecapitalproject. Review long-termdebtfinancingoptions,includingthepotentialissuanceofutilityfirstmortgagebonds,foraportion May 15,2013. fective automaticshelfregistrationstatementonfilewiththeSECunderwhichwemayissue,fromtimetotime, ovisions This shelfregistrationstatementexpiresinJune2014,and weplantofileanewshelfregistration The totalpaymentwas 1.313 percent ’ s 4.8 percent $225 million (LIBORplusamar PollutionControlRevenueBondswerepaidinfullfor As ofDec.31,2013,wehadapproximately seniorunsecured6.50percent $239 million , includingaccruedinterestandamake-wholeprovisionof 100 , ourabilitytoissuesecuritiesislimitedtheauthoritygranted gin of1.125percent notes,whichwereoriginallyscheduledto . At Dec.31,2013,thecostofborrowing ). 44 million 100 million sharesofcommonstock $6.5 million The proceedsfromthis sharesofcommon Although the principaland $7.1 FORM 10K 10K | 101 As , to Act. fectively 2011 $1.46 118% The most . ganization, is junior to the 80% 2012 $1.48 $88 million 59% 2013 s liquidation or reor $1.52 per share or an annualized equivalent dividend or an annualized equivalent $0.39 per share , and all dividends were paid out of available 1.8 percent, and all dividends were Therefore, our holding company debt obligations are ef Therefore, our holding company debt obligations 101 As a result of our holding company structure, our right as a common shareholder As a result of our holding company structure, , will be dependent on our results of operations, financial position, cash flows, reinvestment flows, reinvestment position, cash of operations, financial on our results , will be dependent As of Dec. 31, 2013, we were in compliance with these covenants. The table below provides our historical three-year dividend payout ratio and dividends paid per share. and dividends dividend payout ratio historical three-year below provides our The table , our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory , our utility subsidiaries may generally . For example, the issuance of debt by our utility subsidiaries (including the ability of Black Hills Utility Holdings . For example, the issuance of debt by our An event of default would be deemed to have occurred if we did not meet certain financial covenants. An event of default would be deemed to Dividends Per Share Dividend Payout Ratio to issue debt) and the use of our utility assets as collateral generally requires the prior approval of the state regulators in the assets as collateral generally requires the prior approval of the state regulators to issue debt) and the use of our utility state in which the utility assets are located. As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence utilities, we are subject to various regulations company which owns several regulated As a utility holding our liquidity Dividend Restrictions Our three-year compound annualized dividend growth rate was annualized dividend growth rate Our three-year compound operating cash flows. Credit Facility include the following: a recourse leverage ratio not to restrictive financial covenants of our Revolving net net worth of $625 million plus 50 percent of aggregate consolidated exceed .65 to 1.00 and a minimum consolidated income since Jan. 1, 2005. ratio of agreements require Cheyenne Light to maintain a debt to capitalization Covenants within Cheyenne Light's financing they Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which no more than .60 to 1.00. Our utilities in ratio to debt to third parties and the payment of a dividend would reduce their equity cannot pay dividends if they have issued extend and neither Black Hills Utility Holdings nor its utility subsidiaries can below 40 percent of their total capitalization; course of business and upon reasonable terms consistent with market terms. credit to the Company except in the ordinary Additionally company and also may have further restrictions under the Federal Power authorities to be paid to us as a utility holding Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of contain restrictions on the payment of cash dividends upon a default or Our credit facilities and other debt obligations default. per share. per share. rate of $1.56 indirect subsidiaries upon a subsidiary’ receive assets from any of our direct or by their creditors. claims against the assets of such subsidiaries of the creditors of our subsidiaries, including trade creditors, debt holders, subordinated to all existing and future claims guarantee holders. secured creditors, taxing authorities, and Future cash dividends, if any Future cash Common Stock Dividends Stock Common of a quarterly dividend Directors declared 2014, our Board of In January opportunities and other factors which will be evaluated and approved by our Board of Directors. and approved which will be evaluated and other factors opportunities of Dec. 31, 2013, the restricted net assets at our Electric and Gas Utilities were approximately 102 |10K FORM 10K Net cashprovidedby Operating 2013 The followingtablesummarizesourcashflows(inthousands): CASH FLOW At Dec.31,moneypoolbalancesincluded(inthousands): ultimate parentcompany)ortonon-regulatedaf ultimate parentcompany),themoneypoolarrangementdoesnotallowloansfromourutilitysubsidiariestoCompany(as market-based rates( agreements, ourutilitiesmayattheiroption,borrowandextendshort-termloanstootherviaautilitymoneypool these requirements. activities betweenourutilitysubsidiariesandtheCompany As autilityholdingcompany Utility MoneyPool Cash providedby(usedin) Subsidiary Financing activities Investing activities Operating activities • • • • Cheyenne Light Black HillsPower Black HillsUtilityHoldings Comparedto Total MoneyPoolborrowingsfromParent operating activitiesinourEner sale ofourEner 2013 includedcashoutflowsfromoperatingactivitiesof A from ourde-designatedinterestrateswapsof$6.0million, andothernormalworkingcapitalchanges; million duetotheexpirationofColoradoElectric’ variance primarilyrelatedtoincreasednaturalgasinventory Net outflowfromoperatingassetsandliabilitiesofcontinuingoperations were Cash earnings(incomefromcontinuingoperationsplusnon-cashadjustments)were $13million Activities:
ACTIVITIES 2012 These agreementsareonfilewiththeFERCandappropriatestateregulators.Underutilitymoneypool 1.6 percent contributionin operatingactivitieswas gy Marketingsegmentin2012comparedtowhichincluded a , wearerequiredtoestablishacashmanagementprogramaddresslendingandborrowing atDec.31,2013). 2013 toourdefinedbenefitplanscompared gy Marketingsegment. $7.7 million filiates. While theutilitymoneypoolmayborrowfundsfromCompany(as s contractwithPSCoatDec.31,201 higherthanin . W 102 e haveestablishedutilitymoneypoolagreementswhichaddress $0.9 million , adecreaseinaccountspayableofapproximately$9.0 $ $ $ $ $ 2012 primarilyattributableto: forpost-closingadjustmentsresultingfromthe 2013 (349,278 324,629 (Loans 17,028 2013 $25 million $14 million T ) o) MoneyPoolOutstanding Borrowings From $ $ $ 177,066 128,587 $21 millioncashinflowfrom (17,293 $24 million 65,772 1, thereturnofcashcollateral in2012;and 2012 higherthanprioryear ) (371,446 316,971 $ $ 11,169 higherthanprioryear; ) $ $ $ 2012 2011 (447,007 (31,645 249,633 223,704 27,852 . 1,484 5,277 The ) ) FORM 10K 10K | 103 , ind The . W from 2012 from 2012 from illiston Basin $8.5 million W 2012. 1. higher than prior year; 1; and fset by the use of short- paid in primarily due to the primarily due to the in 201 The redemption of the notes 1, and other normal working inflow of $388 million $47 million from the sale of a majority of our sale of a majority of from the $360 million of $360 outflows $65 million , and settled the de-designated interest 1 million $5.6 million $1 $40 million higher than prior year $228 million 1 primarily attributable to: 201 , the decrease in accounts payable of approximately $9.0 ; 103 6.5 percent notes with proceeds from the sale of Pollution Control Revenue Bonds. higher than in , which was an increase in in 2013, which was an increase on Revolving Credit Facility s contract with PSCo at Dec. 31, 201 were paid in 2013 compared to , which was an increase in increase was an , which in 2013 $7.1 million with proceeds from issuance of a senior unsecured notes for $525 million; with proceeds from issuance of a senior $6.5 million $93 million $17 million $68 million $349 million $349 , repaid $55 million 2012 to our defined benefit plans compared to $64 million yoming project debt for approximately $96 million and settled associated interest rate swaps yoming project debt for approximately W $8.5 million 1 operating activities was financing activities was financing activities contribution in to 201 increase in net cash inflows from discontinued operations in 2012 compared 201 f the Black Hills Activities: Activities: Activities: illiston Basin assets by our Oil and Gas segment, and $25 million from the partial sale of the Busch Ranch the Busch Ranch the partial sale of and $25 million from and Gas segment, assets by our Oil illiston Basin $25 million $14 million required a make-whole provision payment of required a make-whole provision payment of Cheyenne Prairie; and term borrowings to fund the construction Cash dividends on common stock of increase primarily related to decreased gas volumes in inventory million due to the expiration of Colorado Electric’ capital changes; A A In 2012, we repaid short-term borrowings from proceeds from the sale of Enserco partially of In 2012, we repaid short-term borrowings assets and Black Hills Power repaid its assets and Black Hills Power repaid its were Cash earnings (income from continuing operations plus non-cash adjustments) Net inflows from operating assets and liabilities of continuing operations of In 2012, proceeds from sale of assets was $254 million which included which included assets was $254 million from sale of In 2012, proceeds W project; of Enserco; and proceeds of $108 million from the sale In 2012, we received with an increase of capital expenditures to 2012, In 2013, we had comparable Prairie. construction of Cheyenne In 2013, we re-paid $250 million senior unsecured notes plus a make-whole premium of approximately In 2013, we re-paid $250 million senior paid of for approximately rate swaps for approximately term loan for $275 million which was primarily used to repay the $100 In 2013, we entered into a long-term Corporate short-term term loan and a portion of the Revolving Credit Facility; million long-term term loan, the $150 million unsecured In 2012, we repaid our $225 million senior Compared to • • • • • • • • • • • • Net cash provided by 2012 Operating Net cash provided by primarily attributable to: primarily Financing investing activities was activities in investing used Net cash Investing Investing primarily attributable to: primarily attributable 104 |10K FORM 10K long-term debt. expenditures, includingconstructionofCheyennePrairie. generated fromoperationsandborrowingonourexistingRevolving CreditFacilitywillbeadequatetofundongoingcapital our capitalbudgettoNon-regulatedoperationswithspecific focusonouroilandgasdrillingprogram. improve orexpandtheexistinggasdistributionnetwork.In additiontoourutilitycapitalexpenditures,weallocateaportionof generating stations,transmissionanddistributionlines.CapitalexpendituresassociatedwithourGasUtilitiesareprimaril y to 2013, ourElectricUtilities’ of returnauthorizedbythecommissionsinjurisdictionswhichweoperateandaresubjecttorateagreements. During and ifconsideredprudentbyregulators,canberecoveredfromourutilitycustomers. Historically expenditure programduringthenextthreeyears. Capital expendituresareasubstantialportionofourcashrequirementseachyearandwecontinuetoforecastrobust capital CAPIT primarily attributableto: Cash usedinfinancingactivitieswas Financing million Net cashprovidedby Investing • • • • • • In 201 Cash dividendsoncommonstockof required amake-wholeprovisionpaymentof assets andBlackHillsPowerrepaidits In 2012,werepaidour$225millionseniorunsecured primarily duetoourcontinuedconstructioninColorado; used forourworkingcapitalneeds,whilein201 borrowings ontheRevolvingCreditFacility During 2012,approximately$1 generation facility In 2012,wehadlowercapitalexpendituresof Busch Ranch W Cash proceedsfromassetssoldduring2012,including in201 AL illiston BasinassetsbyourOilandGassegment,$25millionfromthesaleofa50percentownershipinterestin Activities: EXPENDITURES Activities: , asignificantportionofourcapitalexpendituresrelateprimarilytoassetsthatmaybeincludedinutilityratebase, 1, weissuedcommonstockforproceedsof 1 foranetinflowof W investingactivitieswas ind project,and . capitalexpendituresincludedthecontinuedconstructionofCheyennePrairie,andimprovementsto $458 million $371 million 10 millionoftheproceedsfromsaleEnsercowereusedtopaydownshort-term $108 millionfromthesaleofEnserco;and $65 million $1 $6.5 million . 1 million The changewasdrivenby: in2012,whichwasanincreaseoutflowof . Additional borrowingsontheRevolvingCreditFacilitywereprimarily $7.1 million $92 million 1 weincreasedshort-termborrowingsbyapproximately werepaidin2012comparedto $123 million in2012comparedtonetcash W PollutionControlRevenueBonds. e wouldultimatelyexpecttofinancethisnewgenerationwith 6.5 percentbondswithproceedsfromthesaleof $228 million 104 ; primarilyduetothecompletionofconstructionourPueblo primarilyfromanequityforwardtransaction. fromthesaleofapproximately85percentour Those capitalexpendituresalsoearnarate $59 million used in The redemptionofthebonds investingactivitiesof $621 million paidin W e believethatcash 201 from201 W 1; and $196 million illiston Basin $447 1
FORM 10K 10K | 105 3,200 7,300 6,100 47,600 158 160,500 122,200 346,900 2,359 8,382 98,927 89,672 13,279 59,202 43,954 10,438 2016 173,078 429,348 431,707 499,449 2011 $ $ $ $ 5,200 6,200 5,900 62,000 — 189,300 122,700 391,300 824 5,547 7,376 2015 65,262 45,711 13,420 167,263 107,839 347,156 347,980 240,077 653,319 2012 $ $ $ $ 2,500 6,600 8,700 63,000 250,700 117,800 449,300 — — 2014 5,528 13,533 64,687 10,319 67,587 63,205 222,262 379,534 379,534 445,906 893,027 $ $ 2013 $ $ 105 1 included costs relating to construction of the 180 megawatt natural gas- 1 included costs relating to construction of ind Project; and 201 W , plant and equipment. (c) (b) (1) : (a) (d)
1 includes costs relating to the construction of the 200 megawatt natural gas-fired power generation facility at Black Hills Colorado 1 includes costs relating to the construction . Electric Utilities Gas Utilities Power Generation Coal Mining Oil and Gas Electric Utilities Gas Utilities Power Generation Coal Mining Oil and Gas Capital expenditures for our Electric Utilities are forecasted to include approximately $68 million associated with the construction of Capital expenditures for our Electric Utilities are forecasted to include approximately Cheyenne Prairie during 2014. Includes accruals for property 2013 includes costs relating to Cheyenne Prairie which began construction in the spring of 2013; 2012 included construction of our 50 2013 includes costs relating to Cheyenne Prairie percent ownership in the Busch Ranch fired generation facility at Colorado Electric. 201 IPP completion delays. Decrease in expenditures due to drilling and e continue to evaluate potential future acquisitions and other growth opportunities which are dependent upon the availability e continue to evaluate potential future acquisitions and other growth opportunities Corporate Utilities - Non-regulated Energy - Non-regulated Energy Utilities: Capital expenditures for continuing operations Capital expenditures investing activities Discontinued operations equipment Total expenditures for property, plant and Common stock dividends Maturities/redemptions of long-term debt Discontinued operations financing activities Non-regulated Energy: Corporate Property additions Property additions W from the estimates identified above. of economic opportunities and, as a result, capital expenditures may vary significantly ______(1) Our primary capital requirements for the three years ended Dec. 31 are expected to be as follows (in thousands): Our primary capital requirements for the Forecasted Capital Requirements (a) (b) Our primary capital requirements for the three years ended Dec. 31 were as follows (in thousands): were as follows (in ended Dec. 31 for the three years capital requirements Our primary Historical Capital Requirements Capital Historical ______(c) (d) 106 |10K FORM 10K issue equitybasedonourcreditratingsorothertriggerevents. or thepostingofadditionalcashcollateral)tiedtoourstock priceandhavenotexecutedanytransactionsthatrequireusto W The followingtablerepresentsthecreditratingsofBlackHillsPowerat incur higherinterestratesundercurrentbankcreditagreements. Moody's. IfeitherS&P Our feesandinterestpaymentsundervariouscorporatedebtagreementsarebasedonthelowestcreditratingofS&P The followingtablerepresentsthecreditratings,outlookandriskprofileofBHCat rating agency recommendations tobuy capital marketsatprevailingmarketratesforcompanieswithcomparablecreditratings.BHCnotesthatratingsarenot performance, liquidityandcreditratingsoftheCompany ratings, cashflowsfromroutineoperationsandthecreditratingsofcounterparties. factors suchasgeneraleconomicandcapitalmarketconditions,regulatoryauthorizationspolicies,thecompany'scredit terms couldnegativelyaf cost andavailabilityofexternalfundsthroughbothshortlong-termfinancing. Financing foroperationalneedsandcapitalexpenditurerequirementsnotsatisfiedbyoperatingcashflowsdependsuponthe CREDIT e donothaveanytriggerevents(i.e.,anaccelerationofrepayment ofoutstandingindebtedness,anincreaseininterestcosts ______(c) (b) (a) ** * ______Fitch Moody's S&P Fitch Moody's ** S&P * RA On May10,2013,FitchupgradedourcreditratingtoBBBwithaPositiveoutlook. Subsequently On Sept.25,2013,Moody’ On July24,2013,S&P On Sept.25,2013,Moody’ On July24,2013,S&P credit ratingto (a) . Eachratingshouldbeevaluatedindependentlyofanyotherrating. TINGS (c) (b) AND COUNTERP orMoody'sdowngradedourseniorunsecureddebt,wewouldberequiredtopayadditionalfeesand , onJan.30,2014,Moody’ , sell,orholdsecuritiesandmaybesubjecttorevisionwithdrawalatanytimebytheassigning fect theCompany'sabilitytomaintainorexpanditsbusinesses. A1. Rating Agency upgradedourcreditratingtoBBBwithaStableoutlook. upgradedtheBHP s upgradedtheBHCcreditratingtoBaa2withaPositiveoutlook. s upgradedtheBHP Rating Agency AR TIES s upgradedtheBHCcreditratingtoBaa1withaStableoutlook. creditratingto creditratingto , managementbelievesthattheCompanywillhaveaccessto 106 A- withaStableoutlook. Senior UnsecuredRating A2. Subsequently Dec. 31,2013: Baa2 BBB BBB The inabilitytoraisecapitalonfavorable After assessingthecurrentoperating Dec. 31,2013: , onJan.30,2014,Moody’ Senior SecuredRating Access tofundsisdependentupon A1 A- A- Outlook Positive Positive Stable s upgradedtheBHP or
FORM 10K 10K | 107 — ge 4,375 22,631 51,851 39,267 23,423 ears Y After 5 gy char 1,122,055 1,263,602 Dec. 31, $ $ Dec. 31, 2013. — — — in 2017, and $59 The ener These hedges are in 2,774 4,080 green contracts and 39,521 ears 4-5 283,036 236,661 Y $ $ — — Dec. 31, 2013. Our transmission 6,268 50,655 10,127 ears 1-3 275,000 410,869 752,919 As, capacity and certain transmission, Y in 2016, $59 million $ $ Annual Report on Form 10-K. — — — Payments Due by Period The impact of these hedges is not included in the ear Than 2,782 5,315 82,500 Y 293,728 203,131 1 Less $ $ portion of our gas purchases are hedged. A associated with the gain deferred from the tax treatment related to associated with the gain deferred from the 16,199 51,851 37,630 82,500 The gathering commitments for our Oil and Gas segment are The gathering commitments for our Oil and -company transactions and obligations negotiated for the 873,292 134,758 Total 1,397,055 2,593,285 These amounts have been excluded as it is impractical to reasonably 107 $ $ portion of our gas purchases are purchased under ever portion of our gas purchases are purchased $6.3 million A in 2014, $60 million in 2015, $59 million gy and capacity costs associated with our PP fice buildings, warehouses and call centers, equipment and vehicles. fice buildings, warehouses and call centers, Annual Report filed on Form 10-K. Dec. 31, 2013. (g) fer materially from these estimated amounts (in thousands): from these estimated fer materially Dec. 31, 2013. $62 million AND OTHER COMMITMENTS OTHER AND ransaction. T (c) fs as of Dec. 31, 2013. This 132 megawatt generating facilities is expected to cost $222 million for which we have secured This 132 megawatt generating facilities is expected to cost $222 million for which we (h) of the Notes to Consolidated Financial Statements in this 7 of the Notes to Consolidated Financial Statements TIONS TIONS Aquila (e) (d) (f) The following information summarizes our cash obligations and commercial commitments at commitments obligations and commercial our cash information summarizes The following OBLIGA The obligations presented above do not include inter (a)(b) As and the commodity price under the gas purchase contracts are variable costs, which for purposes of estimating our future As and the commodity price under the gas purchase of the procurement contracts as of ransaction and the T in 2018. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of in 2018. Estimated interest payments on variable
Actual future costs of obligations may dif costs of obligations Actual future ears 1-3 include an estimated reversal of approximately ears 1-3 include an estimated reversal of approximately under the PP obligations are based on filed tarif obligations, were based on costs incurred during 2013 and price assumptions using existing prices at obligations, were based on costs incurred during gas purchases, gas transportation and storage agreements, and gathering commitments for our Oil and Gas segment. gas purchases, gas transportation and storage described in Part I, Delivery Commitments, of this described in Part I, Delivery Commitments, of Includes operating leases associated with several associated with our Electric Utilities, Gas Utilities, Coal Mining and Oil and Gas Includes estimated asset retirement obligations segments as discussed in Note the IPP therefore, for purposes of this disclosure, are carried out for 60 days. therefore, for purposes of this disclosure, are on to Defined Benefit Pension Plans and payments to employees for the Non-Pensi Represents both estimated employer contributions Plans and the Supplemental Non-Qualified Defined Benefit Plans through the year 2023. Defined Benefit Postretirement Healthcare Y that may arise from our derivatives, including interest rate swaps and commodity Amounts in the table exclude: (1) any obligation related contracts that have a negative fair value at estimate the final amount and/or timing of any associated payments. (2) place to reduce our customers' underlying exposure to commodity price fluctuations. above table. (3) construction of Cheyenne Prairie. 100 percent Long-term debt amounts do not include discounts or premiums on debt. Long-term debt amounts do not include discounts payments over the next five years based on a mid-year retirement date for long-term The following amounts are estimated for interest debt expiring during the identified period: Unconditional purchase obligations include the ener Unconditional purchase obligations include million otal contractual cash obligations Contractual Obligations Long-term debt obligations Unconditional purchase Operating lease obligations Other long-term obligations Employee benefit plans tax benefits in accordance with Liability for unrecognized accounting guidance for uncertain tax positions Notes payable T (d) (e) (f) (g) (h) ______(a) (b) (c) CONTRACTUAL In addition to our capital expenditure programs, we have contractual obligations and other commitments that will need to be commitments that obligations and other we have contractual programs, to our capital expenditure In addition the future. funded in Contractual Obligations Contractual 2013. 108 |10K FORM 10K letters ofcreditissuedunderourRevolvingCreditFacilityat Letters ofcreditreducetheborrowingcapacityavailableonourcorporateRevolvingCreditFacility Letters ofCr W Form 10-K. more informationontheseguarantees,seeNote under subsidiarycontractsand outstanding guaranteesasindicatedinthetablebelow guarantees supportingcertainofoursubsidiariesunderspecifiedagreementsortransactions. W Guarantees Of Indemnification forsubsidiaryreclamation/suretybonds physical andfinancialtransactionsbyBlackHillsUtilityHoldings Guarantees forpaymentofobligationsarisingfromcommodity-related Nature ofGuarantee activities andtoensurethattheseareconductedwithin theauthorizedpolicies. Executive RiskCommittee,whichincludesseniorlevelexecutives, meetsonaregularbasistoreviewourbusinessandcredit control infrastructure,authorizedcommoditiesandtrading instruments,prohibitedactivities,andemployeeconduct. reviewed bythe The BlackHillsCorporationRiskPoliciesandProcedures havebeenapprovedbyourExecutiveRiskCommitteeand rates, andtheliquidityofrelatedinterestratecommodity markets. ener Our exposuretothesemarketrisksisaf following marketrisks,including,butnotlimitedto: Market riskisthepotentiallossthatmayoccurasaresultofanadversechangeinmarketpriceorrate. mitigate theseidentifiedrisks,wehaveadoptedtheBlackHillsCorporationRiskPoliciesandProcedures. our businesses.Dependingontheactivity Our activitiesintheregulatedandnon-regulatedener e hadthefollowingguaranteesinplace(inthousands): e haveenteredintovariousof f-Balance SheetCommitments gy portfolio,theabsoluteandrelativelevelsofinterestrates andcommodityprices,thevolatilityoftheseprices • • described inNotes Interest rateriskassociatedwithourvariabledebtandothershort-termlong-terminstruments production andfuelprocurementforcertainofourgas-firedgenerationassets; Commodity priceriskassociatedwithournaturallongpositioncrudeoilandgasreserves edit Audit CommitteeofourBoardDirectors. 5 and6ofourNotestoConsolidatedFinancialStatements. $64 million f-balance sheetcommitmentsintheformofguaranteesandletterscredit. fected byanumberoffactorsincludingthesize,duration, and compositionofour , weareexposedtovaryingdegreesofmarketriskandcreditrisk. wasrelatedtoindemnificationforreclamationandsuretybondsofsubsidiaries.For 19 oftheNotestoConsolidatedFinancialStatementsinthis Market RiskDisclosur . Ofthe$134million gy sectorsexposeustoanumberofrisksinthenormaloperations Dec. 31,2013. These policiesrelatetonumerousmattersincludinggovernance, 108 , $70million es $ $ Outstanding at Dec. 31,2013 wasrelatedtoperformanceobligations At Dec.31,2013,wehad
134,449 64,449 70,000 . W e had$22million W e areexposedtothe W Annual Reporton T e providevarious o manageand Ongoing Expiring Ongoing Year The in as FORM 10K 10K | 109 fsetting ) o the T . All of our All of our 4,397 (8,533 12,930 yoming and yoming and W 2012 gy cost built into our gy cost built $ $ )
Our natural long positions, or 4,052 (6,071 10,123 e elect hedge accounting on these W -the-counter swaps, exchange traded futures -the-counter swaps, exchange traded futures These transactions are considered derivatives, These transactions are
2013 These adjustments are subject to periodic These adjustments are . $ $ , the hedging activity is recognized in the Consolidated , the hedging activity is recognized in the 109 Accordingly
underlying exposure to these fluctuations. underlying exposure Unrealized and realized gains and losses, as well as option premiums and commissions on these gains and losses, as well as option . Unrealized and realized provisions that allow them to pass the prudently-incurred cost of gas through to the customer cost of gas pass the prudently-incurred that allow them to provisions o the extent that our fuel and purchased power costs are higher or lower than the ener are higher or lower purchased power costs that our fuel and o the extent ference (or a portion thereof) is passed through to the customer ference (or a portion T oup fs, the dif e produce natural gas and crude oil through our exploration and production activities. e produce natural gas and crude oil through e produce, purchase and distribute power in four states, and purchase and distribute natural gas in five states. gas in five states. and distribute natural states, and purchase power in four purchase and distribute e produce, o mitigate commodity price risk and preserve cash flows, we primarily use over o mitigate commodity price risk and preserve Cash collateral Net derivative liabilities and related options to hedge portions of our crude oil and natural gas production. and related options to hedge portions of from proven producing instruments. Our hedging policy allows up to 90 percent of our natural gas and crude oil production commodity contracts are subject to master reserves to be hedged for a period up to three years in the future. Some of our that allow us to settle positive and negative netting agreements, where our asset and liability positions include cash collateral positions. Oil and Gas W price risk and variability to our cash flows. unhedged open positions, result in commodity T Oil and Gas Exploration and Production W Utilities Gr Utilities utilities have GCA utilities have a periodic basis are made on billing rates, adjustments in our current or lower than amounts gas prices are higher extent that Colorado, In South Dakota, gas cost we incurred. match the actual natural billed amounts to to “true-up” for our regulated similar to the GCAs serves a purpose electric utilities that for our regulated we have a mechanism Montana, gas utilities. The operations of our utilities, including power purchase arrangements where our utilities must provide the generation fuel where our utilities must provide utilities, including power purchase arrangements The operations of our allowed or required, by state in natural gas prices; therefore, as expose our utility customers to volatility (tolling agreements), gas futures, options and hedging programs utilizing natural we have entered into commission-approved utility commissions, our customers’ basis swaps to reduce tarif the state utility commissions. prudence reviews by The fair value of our Utilities Group derivative contracts at Dec. 31 is summarized below (in thousands): The fair value of our Utilities Group derivative and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as and hedging, mark-to-market adjustments accounting standards for derivatives and in accordance with of balance sheet of Consolidated Balance Sheets, net Derivative liabilities on the accompanying Derivative assets or as permitted by GAAP are Statements of Comprehensive Income (Loss) when the related costs Statements of Income (Loss) or the Consolidated recovered through our rates. transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets transactions are recorded as Regulatory guidelines. accordance with the state utility commission 110 |10K FORM 10K Annual ReportonForm10-K. Further detailsoftheswapagreementsaresetforthinNote loss ontheaccompanyingConsolidatedBalanceSheets. derivatives andhedgesaccordinglytheirmark-to-market adjustmentsarerecordedin term of3years. obligations. interest rateswapagreementstoreduceourexposure ratefluctuationsassociatedwithourfloatingdebt W Financing purchased powerresourcesexceedouranticipatedloadrequirementsplusarequiredreservemar control suchrisk,werestrictwholesaleof capacity A Wholesale Power Our hedgeagreementshadafairvalue,netofcashcollateral,approximately Crude Oil Natural Gas from theOilandGassegment. W Swaps -Bbls 2015 Swaps -Bbls 2014 Swaps -MMBtu 2015 Swaps -MMBtu 2014 potentialriskrelatedtopowersalesisthepricearisingfromsaleofwholesalethatexceedsourgenerating e engageinactivitiestomanagerisksassociatedwithchangesinterestrates. e haveenteredintoagreementstohedgeaportionofourestimated Weighted AveragePriceperBbl Weighted AveragePriceperBbl Weighted AveragePriceperMMBtu Weighted AveragePriceperMMBtu . These potentialshortpositionscanarisefromunplannedplantoutagesorunanticipatedloaddemands. Activities At Dec.31,2013,wehad$75million These swapshavebeendesignatedascashflowhedgesin accordance withaccountingstandardsfor The hedgeagreementsinplaceasof f-system salestoamountsbywhichouranticipatedgeneratingcapabilitiesand ofnotionalamountfloating-to-fixedinterestrateswaps,with amaximum $ $ $ $ March 31, March 31,
1,132,500 900,000 8 oftheNotestoConsolidatedFinancialStatementsinthis 55,500 60,000 1 89.98 95.48 10 4.24 3.80 Dec. 31,2013,areasfollows: $ $ $ $ 2014 and2015naturalgascrudeoilproduction June 30, June 30, 1,132,500 862,500 51,000 60,000 For theThreeMonthsEnded For theThreeMonthsEnded 87.84 90.65 3.99 3.82 $0.1 million W e haveenteredintofloating-to-fixed $ $ $ $ Sept. 30, Sept. 30, 1,050,000 500,000 39,000 57,000 Accumulated othercomprehensive 87.73 90.55 4.08 3.99 asofDec.31,2013. gin. $ $ $ $ Dec. 31, Dec. 31, 1,050,000 455,000 33,000 57,000 87.36 90.66 4.16 3.99 $ $ $ $ Total Year Total Year 2,717,500 4,365,000 178,500 234,000 T 88.39 91.86 o 4.12 3.90 FORM 10K 10K | 111 — — 1,882 1,882 1.24% 4.45% 5.31% Pre-tax Total Unrealized 294,855 Annual Report Gain (Loss) $ $ $ 1,397,055 1,102,200 ) ) ) $ $ $ — (9,088 (23,980 (23,980 0.20% 5.22% 5.31% Other Pre-tax 19,855 Accumulated Income (Loss) Comprehensive $ $ $ 1,122,055 1,102,200 Thereafter would be realized and $ $ $ — 5,614 16,941 16,941 —% — —% — —% — Non- current Liabilities $ $ $ 2018 $3.5 million $ $ $ 3,474 7,039 88,148 95,187 —% — —% — —% — Current Collateral Liabilities, net of Cash 2017 $ $ $ of the Notes to the Consolidated Financial Statements in this 8 of the Notes to the Consolidated $ $ $ 1 3 4 —% — —% — —% — Years 1 1 Terms in Maximum 1 2016 . Pre-tax non-cash unrealized gain recognized on these swaps prior to settlement $64 million. Pre-tax non-cash unrealized $ $ $ 5.67% 4.97% 5.04% — —% 1.31% 1.31% Weighted 275,000 275,000 Interest Rate fect of interest rate swaps. 2015 Average Fixed $ $ $ 75,000 250,000 400,000 150,000 — —% —% — —% — Notional $ $ $ 2014 (b) $ $ $ (b) (b) (b) (a) . (a) $30 million The average interest rates do not include the ef The average interest rates do not include the Excludes unamortized premium or discount. Certain interest rate swaps designated as cash flow hedges were settled during 2013. See Note designated as cash flow hedges were settled during 2013. Certain interest rate swaps on Form10-K. were settled in November 2013 for approximately These de-designated swaps was verage interest rate verage interest rate verage interest rate A
A Total long-term debt Fixed rate Variable rate A Dec. 31, 2012 Interest rate swaps Interest rate swaps - De-designated Dec. 31, 2013 Interest rate swaps Long-term debt (b) (a) ______, market interest rates and balances, a loss of approximately Based on Dec. 31, 2013, market interest rates and balances, a loss ______(a) , our interest rate swaps and related balances were as follows (dollars in thousands): follows (dollars were as balances and related swaps interest rate , our 31, 2012 , andDec. 31, 2013 On Dec. The table below presents principal amounts and related weighted average interest rates by year of maturity for our long-term and related weighted average interest rates by year of maturity for our long-term The table below presents principal amounts (dollars in thousands): debt obligations, including current maturities reported in pre-tax earnings during the next 12 months. Estimated and realized losses will likely change during the next next 12 months. Estimated and realized losses will likely change during the next reported in pre-tax earnings during the change. twelve months as market interest rates (b) 112 |10K FORM 10K accounting standardsadoptedin See Note1oftheNotestoConsolidatedFinancialStatementsinthis cooperatives andfederalagencies. company At Dec.31,2013,ourcreditexposureincludeda grade counterpartywillnotdefaultsometimeinthefuture. provide assurancethatwewillcontinuetoexperiencethesamecreditlossrateshaveinpast,oraninvestment identified. for estimatedcreditlossesbaseduponourhistoricalexperienceandanyspecificcustomercollectionissuethatwehave customer W agreements. exposure withlesscreditworthycounterpartiesthroughparentalguarantees,prepayments,lettersofcredit,andothersecurity and creditlimitscommensuratewithcounterpartyfinancialstrength,obtainingnettingagreements,securingour W adopted policies. includes seniorexecutives,meetsonaregularbasistoreviewourcreditactivitiesandmonitorcompliancewiththe credit riskwithintolerancesestablishedbytheBoardofDirectors.Inaddition,ourExecutiveRiskCommittee,which adopted theBlackHillsCorporationCreditPolicythatestablishesguidelines,controls,andlimitstomanagemitigate Credit riskistheoffinanciallossresultingfromnon-performancecontractualobligationsbyacounterparty Cr e performongoingcreditevaluationsofourcustomersandadjustlimitsbaseduponpaymenthistorythe e seektomitigateourcreditriskbyconductingamajorityofbusinesswithinvestmentgradecompanies,settingtenor edit Risk . ’ s currentcreditworthiness,asdeterminedbyourreviewoftheircreditinformation. While mostcreditlosseshavehistoricallybeenwithinourexpectationsandprovisionsestablished,wecannot The remainderofourcreditexposurewasconcentratedprimarilyamonginvestmentgradecompanies,municipal 2013 orpendingadoption. New $0.5 million Accounting Pr 1 exposuretoanon-investmentgradeener 12 onouncements Annual ReportonForm10-Kforinformationnew W gy marketing e maintainaprovision . W e have FORM 10K 10K | 113 15 15 17 18 19 1 1 1 1 1 121 122 123 TEMENTS A A T ST DA Y AR 13 1 TED FINANCIAL AND SUPPLEMENT AND O CONSOLIDA T TEMENTS TEMENTS A ST INDEX FINANCIAL Notes to Consolidated Financial Statements Consolidated Statements of Common Stockholders’ Equity for the three years ended Dec. 31, 2013 Consolidated Statements of Common Stockholders’ Consolidated Statements of Cash Flows for the three years ended Dec. 31, 2013 Consolidated Statements of Cash Flows Consolidated Balance Sheets as of Dec. 31, 2013 and 2012 Consolidated Balance Consolidated Statements of Comprehensive Income (Loss) for the three years ended Dec. 31, 2013 of Comprehensive Income (Loss) Consolidated Statements Consolidated Statements of Income for the three years ended Dec. 31, 2013 of Income for the three years ended Consolidated Statements Report of Independent Registered Public Accounting Firm Report of Independent Management’s Report on Internal Controls Over Financial Reporting Controls Over Report on Internal Management’s ITEM 8. ITEM 114 |10K FORM 10K Black HillsCorporation reporting isincludedherein. reporting asofDec.31,2013 statements, hasissuedanattestationreportontheef Deloitte & on ourevaluation,wehaveconcludedthatinternalcontroloverfinancialreportingwasef the designef Or based onthecriteriasetforthinInternalControl-IntegratedFramework(1992) Of Under thesupervisionandwithparticipationofmanagement,includingourChiefExecutiveOf in conditions,orthatthedegreeofcompliancewithpoliciesproceduresmaydeteriorate. any evaluationofef of itsinherentlimitations,internalcontroloverfinancialreportingmaynotpreventordetectmisstatements. to beef All internalcontrolsystems,nomatterhowwelldesigned,haveinherentlimitations. financial statementsforexternalpurposesinaccordancewithgenerallyacceptedaccountingprinciples. a processdesignedtoprovidereasonableassuranceregardingthereliabilityoffinancialreportingandpreparation 13a-15(f) and15d-15(f)undertheSecuritiesExchange W e areresponsibleforestablishingandmaintainingadequateinternalcontroloverfinancialreportingasdefinedinRules ganizations ofthe ficer , weconductedanevaluationoftheef fective canprovideonlyreasonableassurancewithrespecttofinancialstatementpreparationandpresentation.Because T ouche LLP fectiveness ofcontrols,testingtheoperatingef fectiveness tofutureperiodsaresubjecttheriskthatcontrolsmaybecomeinadequatebecauseofchanges T readway Commission. , anindependentregisteredpublicaccountingfirm,asauditorsofBlackHillsCorporation’ Management’ . Deloitte& T s ReportonInternalContr ouche LLP'sreportonBlackHillsCorporation'sinternalcontroloverfinancial fectiveness ofourinternalcontroloverfinancialreportingas This evaluationincludedreviewofthedocumentationcontrols, fectiveness ofBlackHillsCorporation'sinternalcontroloverfinancial Act of1934,asamended. fectiveness ofcontrolsandaconclusiononthisevaluation.Based 1 14 ol over FinancialReporting issuedbytheCommitteeofSponsoring
Our internalcontroloverfinancialreportingis Therefore, eventhosesystemsdetermined fective asof ficer andChiefFinancial Dec. 31,2013. Also, projectionsof Dec. 31,2013, s financial FORM 10K 10K | 115 Internal readway Commission T e believe that our audits provide a s internal control over financial W ganizations of the Accounting Oversight Board (United States). Accounting Oversight Accounting Oversight Board (United States), Accounting Oversight Board (United States), These consolidated financial statements and financial These consolidated , in all material respects, the information set forth , in all material respects, the information , in all material respects, the financial position of Black , in all material respects, the financial position ACCOUNTING FIRM ACCOUNTING 15 1 s management. Our responsibility is to express an opinion on the responsibility is to express an opinion s management. Our An audit includes examining, on a test basis, evidence supporting the amounts and on a test basis, evidence supporting An audit includes examining, issued by the Committee of Sponsoring Or issued by the Committee of Sponsoring An audit also includes assessing the accounting principles used and significant estimates An audit also includes assessing the accounting REGISTERED PUBLIC PUBLIC REGISTERED Also, in our opinion, such financial statement schedules, when considered in relation to the Also, in our opinion, such financial statement America. expressed an unqualified opinion on the Company’ February 25, 2014 expressed an unqualified opinion on the OUCHE LLP T INDEPENDENT s internal control over financial reporting as of December 31, 2013, based on the criteria established in s internal control over financial reporting equity and cash flows for each of the three years in the period ended December 31, 2013. Our audits also ended December 31, 2013. Our audits for each of the three years in the period equity and cash flows OF , South Dakota T ol - Integrated Framework (1992) e have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the “Company”) of Black Hills Corporation and subsidiaries consolidated balance sheets e have audited the accompanying e conducted our audits in accordance with the standards of the Public Company in accordance with the standards of e conducted our audits e have also audited, in accordance with the standards of the Public Company e have also audited, in accordance with o the Board of Directors and Stockholders of of Directors and o the Board statement schedules are the responsibility of the Company’ statement schedules REPOR T Corporation Black Hills Rapid City W income (loss), common statements of income, comprehensive 2013 and 2012, and the related consolidated as of December 31, stockholders’ at Item 15. statement schedules listed in the Index included the financial W financial statements and financial statement schedules based on our audits. and financial statement schedules based financial statements In our opinion, such consolidated financial statements present fairly In our opinion, such consolidated financial W Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial to obtain reasonable assurance about that we plan and perform the audit Those standards require of material misstatement. statements are free disclosures in the financial statements. the overall financial statement presentation. made by management, as well as evaluating reasonable basis for our opinion. flows December 31, 2013 and 2012, and the results of their operations and their cash Hills Corporation and subsidiaries as of accepted ended December 31, 2013, in conformity with accounting principles generally for each of the three years in the period in the United States of taken as a whole, present fairly basic consolidated financial statements therein. the Company’ Contr Minneapolis, Minnesota February 25, 2014 /s/ DELOITTE & and our report dated reporting. 116 |10K FORM 10K A reasonable basisforouropinion. the assessedrisk,andperformingsuchotherproceduresasweconsiderednecessaryincircumstances. assessing theriskthatamaterialweaknessexists,testingandevaluatingdesignoperatingef reporting wasmaintainedinallmaterialrespects.Ourauditincludedobtaininganunderstandingofinternalcontroloverfinancialreporting, standards requirethatweplanandperformtheaudittoobtainreasonableassuranceaboutwhetheref February 25,2014 Minneapolis, Minnesota /s/ DELOITTE& February 25,2014expressedanunqualifiedopiniononthoseconsolidatedfinancialstatementsandstatementschedules. financial statementsandstatementschedulesasoffortheyearended W the based onthecriteriaestablishedin In ouropinion,theCompanymaintained,inallmaterialrespects,ef become inadequatebecauseofchangesinconditions,orthatthedegreecompliancewithpoliciesproceduresmaydeteriorate. evaluation oftheef override ofcontrols,materialmisstatementsduetoerrororfraudmaynotbepreventeddetectedonatimelybasis. Because oftheinherentlimitationsinternalcontroloverfinancialreporting,includingpossibilitycollusionorimpropermanagement material ef assurance regardingpreventionortimelydetectionofunauthorizedacquisition,use,dispositionthecompany’ the companyarebeingmadeonlyinaccordancewithauthorizationsofmanagementanddirectorscompany;(3)providereasonable permit preparationoffinancialstatementsinaccordancewithgenerallyacceptedaccountingprinciples,andthatreceiptsexpenditures transactions anddispositionsoftheassetscompany;(2)providereasonableassurancethatarerecordedasnecessaryto those policiesandproceduresthat(1)pertaintothemaintenanceofrecordsthat,inreasonabledetail,accuratelyfairlyreflect external purposesinaccordancewithgenerallyacceptedaccountingprinciples. other personneltoprovidereasonableassuranceregardingthereliabilityoffinancialreportingandpreparationfinancialstatementsfor and principalfinancialof W control overfinancialreportingbasedonouraudit. Or December 31,2013,basedoncriteriaestablishedin W Rapid City Black HillsCorporation T REPOR Management’ financial reportingandforitsassessmentoftheef o theBoardofDirectorsandStockholders company’ e havealsoaudited,inaccordancewiththestandardsofPublicCompany e conductedourauditinaccordancewiththestandardsofPublicCompany e haveauditedtheinternalcontroloverfinancialreportingofBlackHillsCorporationandsubsidiaries(the“Company”)as ganizations ofthe T readway Commission. T fect onthefinancialstatements. , SouthDakota OF s internalcontroloverfinancialreportingisaprocessdesignedby s ReportonInternalContr INDEPENDENT T fectiveness oftheinternalcontroloverfinancialreportingtofutureperiodsaresubjectriskthatcontrolsmay OUCHE LLP T readway Commission. ficers, orpersonsperformingsimilarfunctions,andef Internal Contr REGISTEREDPUBLIC ol overFinancialReporting The Company’ ol -IntegratedFramework(1992)issuedbytheCommitteeofSponsoringOr fectiveness ofinternalcontroloverfinancialreporting,includedintheaccompanying Internal Contr s managementisresponsibleformaintainingef ol -IntegratedFramework(1992)issuedbytheCommitteeofSponsoring ACCOUNTING FIRM fective internalcontroloverfinancialreportingasof . OurresponsibilityistoexpressanopinionontheCompany’ 1 16 , orunderthesupervisionof,company’ fected bythecompany’ Accounting OversightBoard(UnitedStates),theconsolidated A company’ Accounting OversightBoard(UnitedStates). December 31,2013oftheCompanyandourreportdated s internalcontroloverfinancialreportingincludes fectiveness ofinternalcontrolbasedon fective internalcontroloverfinancial s boardofdirectors,management,and W fective internalcontrolover e believethatourauditprovidesa s assetsthatcouldhavea Also, projectionsofany December 31,2013 s principalexecutive Those ganizations of s internal , FORM 10K 10K | 117 — — 932 710 1.01 0.24 1.25 1.01 0.23 1.24 (817) 9,365 1,121 2,490 2,017 39,864 40,081 49,730 40,365 57,468 14,041 11,260 33,710 93,453 (18,224) (42,010) 186,239 135,591 574,989 247,496 116,669 (128,771) (116,684) 1,085,949 1,272,188 1,155,519 Dec. 31, 2011 Dec. 31, $ $ $ $ $ $ 10 (71) 682 540 2.02 1.86 2.01 1.85 (0.16) (0.16) 2,486 3,462 1,882 1,957 2,052 (6,977) 44,073 43,820 81,528 88,505 40,487 26,868 85,830 (48,400) (29,129) 136,895 243,711 930,173 154,632 407,066 242,367 109,071 (106,816) (117,754) 1,173,884 1,064,813 Dec. 31, 2012 Dec. 31, $ $ $ $ $ $ — — (86) 607 2.62 2.60 2.61 2.59 (884) (694) (0.02) (0.02) 1,971 1,130 1,061 1,723 1,243 44,419 44,163 30,169 40,012 83,762 84,719 (61,608) (78,012) 114,962 115,846 177,540 255,552 141,217 492,147 261,919 (113,979) (in thousands, except per share amounts) (in thousands, 1,020,300 1,275,852 1,191,133 Dec. 31, 2013 Dec. 31, INCOME $ $ $ $ $ $ TION 17 TEMENTS OF TEMENTS 1 A TED ST TED BLACK HILLS CORPORA HILLS BLACK CONSOLIDA The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. The accompanying Notes to Consolidated Financial Statements are an integral part of Total income (loss) per share, Basic Total income (loss) per share, Diluted Total other income (expense) Total operating expenses Income (loss) from continuing operations, per share Income (loss) from discontinued operations, per share Income (loss) from continuing operations, per share Income (loss) from discontinued operations, per share Allowance for funds used during construction - borrowed Allowance for funds used during construction Interest expense incurred (including amortization of debt issuance costs, Interest expense incurred (including amortization on interest rate swaps) premiums and discounts and realized settlements Capitalized interest Fuel, purchased power and cost of natural gas sold Fuel, purchased power Operations and maintenance Diluted Basic Other income Unrealized gain (loss) on interest rate swaps, net Unrealized gain (loss) on interest rate swaps, Interest income - equity Allowance for funds used during construction Other expense Utilities - Non-regulated energy Non-regulated Utilities Earnings (loss) per share of common stock: Earnings (loss) per share, Basic - Earnings (loss) per share, Diluted - Weighted average common shares outstanding: Income (loss) from discontinued operations, net of tax Net income (loss) available for common stock Equity in earnings (loss) of unconsolidated subsidiaries Equity in earnings (loss) of unconsolidated Income tax benefit (expense) Income (loss) from continuing operations Income (loss) from continuing operations before earnings (loss) of Income (loss) from continuing operations before unconsolidated subsidiaries and income taxes Other income (expense): Interest charges - Operating income Other operating expenses Taxes - property, production and severance Impairment of long-lived assets Impairment of long-lived Gain on sale of operating assets Gain on sale of operating and amortization Depreciation, depletion Non-regulated energy operations and maintenance Non-regulated energy Operating expenses: Total revenue Revenue: Year ended Year 118 |10K FORM 10K Comprehensive income(loss) Other comprehensiveincome(loss),netoftax: Net income(loss)availableforcommonstock Years ended(inthousands) respectively) in netincome(loss)(netoftax$(2,016),$534and$(709), Reclassification adjustmentofcashflowhedgessettledandincluded (net oftax$(2,445),$887and$1,708,respectively) Fair valueadjustmentonderivativesdesignatedascashflowhedges cost (netoftax$88,$0and$0) Reclassification adjustmentofbenefitplanliability-priorservice (net oftax$(971),$0and$0) Reclassification adjustmentofbenefitplanliability-netgain(loss) $185, $86and$176,respectively) Benefit planliabilityadjustments-priorservice(costs)(netoftax $(3,813), $296and$4,135,respectively) Benefit planliabilityadjustments-netgain(loss)(netoftax Other comprehensiveincome(loss),netoftax The accompanyingNotestoConsolidatedFinancialStatementsareanintegralpartoftheseStatements. CONSOLIDA See Note15foradditionaldisclosuresrelatedtoComprehensiveIncome. TED ST A BLACK HILLSCORPORA TEMENTS OF 1 COMPREHENSIVEINCOME(LOSS) 18 $ $ TION Dec. 31,2013 133,028 114,962 18,066 4,046 4,534 1,820 8,237 (165 (406 ) ) $ $ Dec. 31,2012 78,918 81,528 (2,610 (1,268 (643 (157 (542 — — ) ) ) ) ) $ $ Dec. 31,2011 40,433 49,730 (9,297 (2,831 (7,609 1,468 (325 — — ) ) ) ) FORM 10K ) 10K | 119 — 510 7,916 3,236 3,620 15,462 77,643 77,231 31,125 28,795 16,402 19,420 163,698 405,106 353,396 188,268 565,214 3,930,772 3,729,471 2,742,749 (1,188,023 Dec. 31, 2012 $ $ ) 2 As of — 717 7,841 1,460 3,397 (in thousands) 16,697 88,478 18,889 24,451 25,877 27,906 345,288 522,896 177,573 353,396 138,197 4,259,445 3,875,178 2,990,297 (1,269,148 Dec. 31, 2013 $ $ TION 19 1 TED BALANCE SHEETS BALANCE TED BLACK HILLS CORPORA HILLS BLACK CONSOLIDA ASSETS The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. The accompanying Notes to Consolidated Financial Total current assets Total other assets, non-current Total property, plant and equipment, net Cash and cash equivalents Restricted cash and equivalents Restricted cash and net Accounts receivable, and fuel Materials, supplies Derivative assets, current net Income tax receivable, assets, net, current Deferred income tax Regulatory assets, current Other current assets Less accumulated depreciation and depletion Goodwill Intangible assets, net Derivative assets, non-current Regulatory assets, non-current Other assets, non-current Current assets: Investments Property, plant and equipment TOTAL ASSETS Other assets: 120 |10K FORM 10K TOTAL LIABILITIESANDSTOCKHOLDERS’EQUITY Stockholders’ equity: Commitments andcontingencies(SeeNotes5,6,7,8,13,17,19) Deferred creditsandotherliabilities: Long-term debt,netofcurrentmaturities Current liabilities: Accumulated othercomprehensiveincome(loss) Treasury stockatcost-50,877and71,782shares,respectively Retained earnings Additional paid-incapital 44,278,189 shares,respectively Common stock$1parvalue;100,000,000sharesauthorized;issued:44,550,239and Other deferredcreditsandotherliabilities Benefit planliabilities Regulatory liabilities,non-current Derivative liabilities,non-current Deferred incometaxliabilities,net,non-current Current maturitiesoflong-termdebt Notes payable Regulatory liabilities,current Accrued incometax,net Derivative liabilities,current Accounts payable Accrued liabilities Total stockholders’equity Total deferredcreditsandotherliabilities Total currentliabilities The accompanyingNotestoConsolidatedFinancialStatementsare anintegralpartoftheseConsolidatedFinancialStatements. LIABILITIES ANDSTOCKHOLDERS’EQUITY CONSOLIDA BLACK HILLSCORPORA TED BALANCESHEETS (Continued) 120 TION $ $ Dec. 31,2013 (in thousands,exceptshareamounts) 1,307,748 3,875,178 1,396,948 540,244 742,344 792,088 133,279 111,479 109,429 432,287 378,394 151,277 130,416 (17,422) 44,550 82,500 10,727 (1,968) 5,614 3,474 — — As of $ $ Dec. 31,2012 1,232,509 3,729,471 492,869 733,095 823,196 125,294 167,397 127,656 385,908 938,877 734,889 103,973 277,000 154,389 (35,488) 44,278 16,941 13,628 96,541 84,422 (2,245) 4,936 FORM 10K ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) 10K | 121 — — — — — 583 (158 7,010 5,655 5,643 (4,533 (5,799 (9,365 (2,359 (8,382 (1,666 22,290 40,365 42,010 33,600 14,586 26,330 32,438 49,730 58,768 (31,091 (11,050 (13,721 (21,385 (59,202 216,694 223,704 135,591 123,041 249,791 249,633 (440,698 (444,648 (447,007 (821,300 1,017,300 Dec. 31, 2011 Dec. 31, . $ $ ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) ) — — — (180 (824 6,343 5,555 8,271 4,929 4,726 6,977 (6,670 (1,882 (2,833 21,184 13,739 11,169 88,505 26,868 39,716 20,973 58,768 81,528 15,462 (10,713 (25,350 (95,518 (65,262 (29,129 (43,306 295,787 316,971 253,791 107,511 154,632 203,753 (349,129 (271,753 (240,077 (371,446 (371,446 Dec. 31, 2012 Dec. 31, (in thousands) $ $ 1 and 2010 respectively ) ) ) ) ) ) ) ) ) ) ) ) ) ) — — — — — — 312 884 (884 5,471 6,763 9,826 4,354 7,841 (5,770 (7,621 15,336 12,595 63,784 22,194 17,028 15,462 17,028 (12,500 (13,921 (30,169 (67,587 (63,939 (15,394 325,513 324,629 115,846 141,217 337,650 800,000 114,962 (354,749 (349,278 (349,278 (532,150 (445,906 at Dec. 31, 201 Dec. 31, 2013 Dec. 31, $ $ CASH FLOWS CASH TION and $16 million 121 TEMENTS OF TEMENTS A $37 million TED ST TED 16 for supplemental disclosure of cash flow information. BLACK HILLS CORPORA HILLS BLACK See Note CONSOLIDA The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. The accompanying Notes to Consolidated Financial Statements are an integral part of Net change in cash and cash equivalents Accounts payable and other current liabilities Materials, supplies and fuel current assets Accounts receivable, unbilled revenues and other Depreciation, depletion and amortization Depreciation, depletion and amortization Deferred financing cost assets Impairment of long-lived assets Gain on sale of operating Stock compensation interest rate swaps, net Unrealized (gain) loss on Deferred income taxes Employee benefit plans Other adjustments, net Cash and cash equivalents include cash of discontinued operations of Contributions to defined benefit pension plans Other operating activities, net Property, plant and equipment additions Proceeds from sale of assets Other investing activities Change in certain operating assets and liabilities: Change in certain operating Adjustments to reconcile income (loss) from continuing operations to net cash provided from continuing operations to reconcile income (loss) Adjustments by operating activities: Dividends paid on common stock Common stock issued Short-term borrowings - issuances Short-term borrowings - repayments Long-term debt - issuance Long-term debt - repayments De-designated interest rate swap settlement Other financing activities Cash and cash equivalents beginning of year * Cash and cash equivalents end of year * (Income) loss from discontinued operations, net of tax from discontinued operations, (Income) loss Net cash provided by operating activities of continuing operations Net cash provided by operating activities of continuing of discontinued operations Net cash provided by (used in) operating activities Net cash provided by operating activities Investing activities: of continuing operations Net cash provided by (used in) investing activities Proceeds from sale of business operations of discontinued operations Net cash provided by (used in) investing activities Operating activities: available for common stock Net income from continuing operations Income (loss) Net cash provided by (used in) investing activities Financing activities: Net cash provided by (used in) financing activities of continuing operations Net cash provided by (used in) financing activities of discontinued operations Year ended Net cash provided by (used in) financing activities ______* 122 |10K FORM 10K Dividends persharepaidwere Net income(loss)availableforcommonstock Other comprehensiveincome(loss),netoftax Balance atDec.31,2010 amounts) (in thousandsexceptshareandper Dividends oncommonstock Net income(loss)availableforcommonstock Other comprehensiveincome(loss),netoftax Balance atDec.31,2011 Other stocktransactions Dividend reinvestmentandstockpurchaseplan Issuance ofcommonstock Tax effectofshare-basedcompensation Share-based compensation Dividends oncommonstock Share-based compensation Net income(loss)availableforcommonstock Balance atDec.31,2012 Other stocktransactions Dividend reinvestmentandstockpurchaseplan Tax effectofshare-basedcompensation Other comprehensiveincome(loss),netoftax Dividends oncommonstock Balance atDec.31,2013 Share-based compensation Other stocktransactions Dividend reinvestmentandstockpurchaseplan Tax effectofshare-basedcompensation
The accompanyingNotestoConsolidatedFinancialStatementsareanintegralpartoftheseStatements.
$1.52, $1.48and$1.46fortheyearsended CONSOLIDA TED ST 39,280,048 43,957,502 44,278,189 44,550,239 Shares 4,413,519 Common Stock 102,511 161,424 219,946 100,741 190,172 A 15,000 66,878 BLACK HILLSCORPORA TEMENTS OF — — — — — — — — — — — — — — $ $ $ $ Value 39,280 43,958 44,278 44,550 4,414 103 161 220 100 190 Dec. 31,2013,2012and201 — — — — — — — — — — — — — 15 67 — 122 COMMONST Shares (20,905 10,962 32,766 21,804 39,016 71,782 50,877 Treasury Stock — — — — — — — — — — — — — — — — — — — ) $ $ $ $ TION Value OCKHOLDERS’ (1,275 (2,245 (1,968 (309 (970 (661 277 — — — — — — — — — — — — — — — — — — — ) ) ) ) ) ) 1, respectively $ $ $ $ Additional Capital Paid in 598,805 722,623 115,216 733,095 742,344 3,099 5,576 7,095 3,282 3,062 5,400 117 377 410 (45 (28 (22 — — — — — — — — — EQUITY ) ) ) . $ $ $ $ Earnings Retained 486,075 476,603 492,869 114,962 540,244 (59,202 (65,262 (67,587 49,730 81,528 — — — — — — — — — — — — — — — — ) ) ) $ $ $ $ AOCI (23,581 (32,878 (35,488 (17,422 18,066 (9,297 (2,610 — — — — — — — — — — — — — — — — — — — ) ) ) ) ) ) $ $ $ $ 1,100,270 1,209,336 1,232,509 1,307,748 Total 119,630 114,962 (59,202 (65,262 (67,587 49,730 81,528 18,066 (9,297 (2,610 3,202 5,076 6,040 3,382 3,129 5,867 117 392 410 (45 (28 (22 ) ) ) ) ) ) ) ) FORM 10K 10K | 123 gas yoming, W . yoming, Colorado and yoming, Colorado and gy W e are a holding company e are a holding company . W gy fer materially from those 21 for additional information. , South Dakota. TEMENTS A ST WRDC, engages in coal mining activities WRDC, engages in coal mining activities 1 TION and its subsidiaries, engages in crude oil and natural and its subsidiaries, engages in crude oil , wind project or transmission tie and the BHEP . Gas Utilities consist of the operating results of the . Gas Utilities consist 4. requires management to make estimates and assumptions that requires management to make estimates 123 ACCOUNTING POLICIES ACCOUNTING
4. TED FINANCIAL TED yo. and vicinity W , 2012 and 201 Dec. 31, 2013 BLACK HILLS CORPORA HILLS BLACK -company balances and transactions have been eliminated in consolidation. For -company balances and transactions have been eliminated in consolidation. For gy Marketing segment, which resulted in this segment being classified as gy Marketing segment, which resulted gy company headquartered in Rapid City gy company headquartered O CONSOLIDA primary business groups: Utilities and Non-regulated Ener two primary business groups: T AND SIGNIFICANT All inter 21 for additional information. esentation gy Marketing segment, amounts associated with this segment have been reclassified as gy Marketing segment, amounts associated with this segment have been reclassified NOTES NOTES -company revenues, see Note 3 for additional information. gy Group includes our Power Generation, Coal Mining and Oil and Gas segments. Power Generation, gy Group includes our Power Generation, yo. Oil and Gas, which is conducted through BHEP yo. Oil and Gas, which is conducted through These businesses are aggregated for reporting purposes as Non-regulated Ener These businesses are aggregated for reporting W yoming and Colorado. Coal Mining, which is conducted through yoming and Colorado. Coal Mining, which W BUSINESS DESCRIPTION DESCRIPTION BUSINESS e use the proportionate consolidation method to account for our working interests in oil and gas properties and for our e use the proportionate consolidation method to account for our working interests fect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the and liabilities and disclosure of contingent assets and liabilities at the date fect the reported amounts of certain assets exas and California. Black Hills Corporation is a diversified ener Black Hills Corporation (1) Description Business that, through our subsidiaries, operates in that, through our subsidiaries, the operating results of Utilities segments. Electric Utilities include includes our Electric Utilities and Gas The Utilities Group and natural gas utility and Colorado Electric, and the electric utility operations of Black Hills Power the regulated electric utility services to areas in South Dakota, Light, which supply regulated electric operations of Cheyenne gas utility services to Cheyenne, Montana and natural The Non-regulated Ener regulated natural gas utility operations of Colorado Gas, Nebraska Gas, Iowa Gas, and Kansas Gas. utility operations of Colorado Gas, Nebraska regulated natural gas Electric Generation and its subsidiaries, engages in independent power generation which is conducted through Black Hills activities in located near Gillette, The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority- The consolidated financial statements include the accounts of Black Hills Corporation which we have the ability to exercise significant owned and controlled subsidiaries. Investment in non-controlled entities over method of accounting. In applying the equity influence over operating and financial policies are accounted for using the equity adjusted for our proportionate share of method of accounting, the investments are initially recognized at cost, and subsequently of pretax income is recorded as Equity earnings earnings and losses and distributions. Under this method, a proportionate share (loss) of unconsolidated subsidiaries. financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and of revenues and expenses during the reporting period. Changes in facts financial statements and the reported amounts may result in revised estimates and actual results could dif circumstances or additional information Principles of Consolidation gas exploration and production activities in Colorado, Louisiana, Montana, Oklahoma, New Mexico, North Dakota, gas exploration and production activities Ener On Feb. 29, 2012, we sold Enserco, our discontinued operations. See Note business segments, see Note For further descriptions of our reportable Use of Estimates and Basis of Pr in conformity with GAAP The preparation of financial statements af estimates. additional information on inter T companies beginning with their acquisition date. Our Consolidated Statements of Income include operating activity of acquired W ownership interest in any jointly-owned electric utility generating facility processing plant. See Note As a result of the sale of our Ener discontinued operations on the accompanying Consolidated Financial Statements. See Note discontinued operations on the accompanying Consolidated Financial Statements. 124 |10K FORM 10K Following isasummaryofaccountsreceivableasDec.31(inthousands): executed withthesamecounterparty right toreclaim,ortheobligationreturn,cashcollateralagainstfairvalueamountsrecognizedforderivativeinstruments netting agreementbetweencounterparties. right of other thatprovideforthenetsettlementofallcontractsineventdefaultonorterminationanyonecontract. W under thecontracthasexpired. general economicconditions. af circumstances change,ourestimateoftherecoverabilityaccountsreceivablecouldbeaf accounts againstamountsduetoreducethenetreceivablebalanceamountwereasonablyexpectcollect.However In specificcaseswhereweareawareofacustomer receivable balancesandcurrenteconomicconditionsthatmayaf review ourtradereceivableallowancebyconsideringsuchfactorsashistoricalexperience,creditworthiness,theageof W due fromsalesofcoal,crudeoilandnaturalgas,electricener write-of other customers,allofwhichdonotbearinterest. Accounts receivableforourUtilitiesGroupprimarilyconsistsofsalestoresidential,commercial,industrial,municipaland Accounts Receivableand classified theseamountsasrestrictedcash. readily haveaccesstotheseaccountsandcouldonlywithdrawfundsuponmeetingcertainrequirements. The BlackHills Restricted CashandEquivalents W Cash andEquivalents Total Corporate Oil andGas Coal Mining Power Generation Gas Utilities Electric Utilities fect ourestimatesinclude,butarenotlimitedto,customercreditissues,thelevelofcommodityprices,deposits and e utilizemasternettingagreementswhichconsistofanagreementbetweentwopartieswhohavemultiplecontractswith each e maintainanallowancefordoubtfulaccountswhichreflectsourestimateofuncollectibletradereceivables. e considerallhighlyliquidinvestmentswithanoriginalmaturityofthreemonthsorlesstobecashequivalents. fs andallowancefordoubtfulaccounts. fset exists,accountingstandardspermitthenettingofreceivablesandpayablesunderalegallyenforceablemaster W yoming projectfinancingrequiredthatwemaintaincashaccountsforvariousspecifiedpurposes. 2013 Allowance for Accounts arewrittenof . Doubtful Accounting standardsalsopermitof This projectfinancingwasrepaidin2013. Accounts receivableforourNon-regulatedEner These accountsreceivablearestatedatbilledandunbilledamountsnetof $ $ ’ s inabilityorreluctancetopay Accounts f oncetheyaredeemedtobeuncollectibleorthetimeallowedfordispute Receivable, Accounts Trade 113,792 gy andcapacity 49,162 52,437 124 8,156 1,711 1,722 fect collectibility 604 $ $ Revenue Unbilled . fsetting offairvalueamountsrecognizedforthe 41,195 65,018 23,823 . , werecordanallowancefordoubtful — — — — $ $ Less Allowance fected. Circumstanceswhichcould for Doubtful Accounts gy Groupconsistsofamounts (1,237 (558 (666 (13 — — — Therefore, wehad ) ) ) ) $ $ Receivable, net W e regularly Accounts W When the e didnot 177,573 89,799 75,594 8,143 1,711 1,722 , if 604 FORM 10K 10K | 125 16 gy 799 2,247 8,589 77,798 71,235 11,603 43,397 25,657 77,643 163,698 Accounts Receivable, net Receivable, $ $ Dec. 31, 2012 ) ) ) ) — — — (19 $ $ The transportation costs (768 (222 (527 6,213 50,196 32,069 88,478 Accounts for Doubtful Less Allowance Less $ $ The sales price for natural gas, crude oil, The sales price for natural gas, crude oil, — — — — Dec. 31, 2013 39,962 63,805 23,843 $ $ The value of our natural gas in storage fluctuates Unbilled Revenue $ $ 16 799 2,247 125 31,495 11,622 54,482 100,661 Trade Accounts Receivable, $ $ fect in our jurisdictions. Each month the estimated unbilled revenue amounts are fect in our jurisdictions. Each month the This estimate is calculated based upon several factors including billings through This estimate is calculated based upon , and delivery of service are generally recorded when service is rendered or ener , and delivery of service are generally recorded gy . Natural gas in storage primarily represents gas purchased for use by our gas customers. . Natural gas in storage primarily represents gas purchased for use by our gas o the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an o the extent that deliveries have occurred T Accounts receivable, net on the accompanying Consolidated Balance Sheets. Accounts receivable, net on the accompanying 2012 Total materials, supplies and fuel Gas Utilities Power Generation Coal Mining Oil and Gas Corporate Total Fuel - Electric Utilities Natural gas in storage held for distribution Materials and supplies Electric Utilities The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated are included in Materials, supplies and fuel on the accompanying Consolidated The following amounts by major classification Balance Sheets as of (in thousands): Materials, Supplies and Fuel is delivered to customers. costs and other related deductions when applicable. condensate and NGLs is adjusted for transportation or historical data and do not require significant judgment. and other deductions are based on contractual Natural gas and crude oil sales are recognized when the products are sold to a purchaser at a fixed or determinable price, when the products are sold to a purchaser at a fixed or determinable price, Natural gas and crude oil sales are recognized and collectibility of the revenue is reasonably assured. Our Oil and Gas segment delivery has occurred, title has transferred volumes and contracted sales prices. records its share of revenues based on production For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for agreements, revenue is recognized either in accordance with accounting standards For long-term non-regulated power sales for accounting standards for leases, as appropriate. Under accounting standards revenue recognition, or in accordance with the life recognized as the lesser of the amount billed or the average rate expected over revenue recognition, revenue is generally of the agreement. estimate of the revenue since the latest billing. estimate of the revenue since the latest in ef the last billing cycle in a month, and prices trued-up and recorded in Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the rates approved by the state regulatory agencies and the FERC. Revenues related Utility revenues are based on authorized sale, transmission and distribution of ener Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has an arrangement with a fixed or determinable when there is persuasive evidence of Revenue is recognized net basis (excluded from from our customers is recorded on a have been rendered. Sales tax collected occurred or services Revenue). Revenue Recognition Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas, Materials and supplies represent parts and supplies for all of our business segments. and coal on hand used to produce power All of our Materials, supplies and fuel are valued using weighted-average cost. natural gas. with seasonal volume requirements of our business and the commodity price of 126 |10K FORM 10K the fullcost“ceiling”atperiodend,apermanentnon-cash write-downwouldbechar calculated usingthepriceatfirstdayofeachmonthfor eachofthepreceding12months.Ifnetcapitalizedcostsexceed period commoditypricesadjustedforcontractedpricechangesandheldconstantthelifeofreserves. unproved propertiesincludedinthenetcapitalizedcosts.FuturecashflowsareestimatedbasedonSEC-defined end-of- future netcashflowsdiscountedatanSECrequiredrate,ofrelatedtaxef Under thefullcostmethod,netcapitalizedcostsaresubjecttoaceilingtestwhichlimitsthesepresentvalue of expected tobeincludedincostsamortizedwithinthetermofunderlyingleaseagreementwhichvarieslength. impairment atleastannuallyandanyamountofisaddedtothecostsbeamortized. not provedreservescanbeassignedtotheproperties. amortized. Costs directlyassociatedwithunprovedpropertiesandmajordevelopmentprojects,ifany recognized againonthesaleofmajorityour properties, aretypicallytreatedasadjustmentstothecostofpropertieswithnogainorlossrecognized.However based onvolumesproducedandprovedreserves. abandonment costs,netofestimatedsalvagevaluesarecapitalized. exploration andestimatedfutureexpenditurestobeincurredindevelopingprovedreservesaswellreclamation and W Oil andGasOperations components, aunit-of-productionmethodologybasedonplanthoursrunisused. a unit-of-productionmethodbasedonvolumesproducedandestimatedreserves.Forcertainnon-utilitypowerplant applicable estimatedservicelifeofthevariousclassproperty Depreciation provisionsforproperty rate regulations,arechar losses recognizedasacomponentofoperatingincome.Ordinaryrepairsandmaintenanceproperty Retirement ordisposalofallotherassets,exceptforcrudeoilandnaturalgaspropertiesasdescribedbelow related toourregulatedpropertiesarereclassifiedfromaccumulateddepreciationandreflectedasregulatoryliabilities. less salvagepluscostofremoval,ischar The costofregulatedutilityproperty Sheets. incurred. recognized asliabilitieswithanincreasetothecarryingamountsofrelatedlong-livedregulatedutilityassetsinperiod construction projects.Inaddition,assetretirementcostsassociatedwithtangiblelong-livedregulatedutilityassetsare utility project. AFUDC, whichrepresentstheapproximatecompositecostofborrowedfundsandareturnonequityusedtofinanceregulated Additions toproperty Pr additional reservecategories. Companies arepermittedbutnotrequiredtodiscloseprobable andpossiblereserves. producing wellinourvolumereserveestimate.Seeinformation onouroilandgasdrillingactivitiesinNote booked atmorethanonelocationawayfromaproducingwell. to thoseestablishedbyproductionandflowtestdata. The SECdefinitionof“reliabletechnology”permitstheuse ofanyreliabletechnologytoestablishreservevolumesinaddition and Gassegmentin2012.Noceilingtestwrite-downwas recorded in2013or201 of lowernaturalgasprices,werecordedanon-cashceiling testimpairmentofoilandgaslong-livedassetsincludedintheOil e accountforouroilandgasactivitiesunderthefullcostmethod.Undermethod,costsrelatedtoacquisition, operty , PlantandEquipment The amountscapitalizedareincludedinProperty These excludedcostsaresubsequentlyincludedwithinthetobeamortizedwhenitisdeterminedwhetheror W e alsocapitalizeinterest,whenapplicable,onundevelopedleaseholdcostsandcertainnon-regulated , plantandequipmentarerecordedatcost.Includedinthecostofregulatedconstructionprojectsis ged tooperationsasincurred. , plantandequipmentaregenerallycomputedonastraight-linebasisbasedthe , plantandequipmentretired,orotherwisedisposedofintheordinarycoursebusiness, ged toaccumulateddepreciation.Removalcostsassociatedwithnon-legalobligations Any conveyancesofproperties,includinggainsorlossesonabandonment W illiston Basinassetsin2012.SeeNote This definitionallows,butdoesnotrequireus,tocalculate PUDstobe The propertiesexcludedfromthecoststobeamortizedareassessedfor , plantandequipmentontheaccompanyingConsolidatedBalance 126 W . Capitalizedcoalminingcostsandleasesareamortizedon e electedtoincludePUDsofonlyonelocationawayfrom a These costsareamortizedusingaunit-of-productionmethod fects, plusthelowerofcostorfairvalue 1. SeeNote ged toearningsinthatperiod. W e haveelectednottoreportonthese , areexcludedfromthecoststobe 21 forfurtherdiscussion. 12 foradditionalinformation. These costsaregenerally , exceptasallowedunder , resultingainsor An averagepriceis 20. As aresult , we FORM 10K ) 10K | 127 e — — — W (226 4,069 3,843 353,396 353,396 353,396 Total 2011 $ $ $ — — The accounting for This analysis $246 million, or 72 8,765 8,765 8,765 $ $ ) Power — Generation (223 3,843 3,620 $ $ $ 20 years. Changes to intangible — — 2012 94,144 94,144 94,144 . 30 each year (or more frequently if (or more frequently . 30 each year e believe that the goodwill amount reflects e believe that the goodwill Gas Utilities $ $ $ W $ $ — — ferences in the settlement of the liability and the ) e estimated the fair value of the goodwill using the fair value of the e estimated — 7. W (223 250,487 250,487 250,487 3,620 3,397 ference in the actual cost of the settlement of the Electric Utilities ransaction was allocated approximately ransaction was allocated $0.2 million for each year of the next five years. T $ $ $ Any dif 2013 127 . . 30, 2013 , to the Gas Utilities. , to the Gas Utilities. ARO accretion expense for our non-regulated operations is included Aquila $ $ ger multiples for comparable companies. ger multiples for comparable , or 28 percent multiple method, and an analysis of comparable transactions. an analysis of comparable transactions. multiple method, and The associated , EBITDA This goodwill from the This goodwill from $94 million The asset is then depreciated or depleted over the appropriate useful life and the liability is The asset is then depreciated or depleted over the appropriate useful life and the Additional information is included in Note . Intangible assets with a finite life continue to be amortized over their estimated useful lives. estimated useful amortized over their life continue to be assets with a finite . Intangible Assets The finite lived intangible assets are currently being amortized over The finite lived intangible assets are currently ransaction. T Aquila ement Obligations , to Colorado Electric and , to Colorado Electric Amortization expense for existing intangible assets is expected to be Additions (adjustments) Amortization expense * Additions (adjustments) Additions (adjustments) e initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent e initially record liabilities for the present value of retirement costs for which e performed our annual goodwill impairment tests as of Nov impairment tests our annual goodwill e performed Intangible assets, net, beginning balance Intangible assets, net, ending balance Ending balance at Dec. 31, 2011 Ending balance at Dec. 31, 2012 Ending balance at Dec. 31, 2013 Asset Retir assets require that the present value of Accounting standards for asset retirement obligations associated with long-lived with an equivalent amount added to the asset cost retirement costs for which we have a legal obligation be recorded as liabilities and depreciated over an appropriate period. accreted over time by applying an interest method of allocation. * W amount added to the asset cost. the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the the obligation for regulated operations has no income statement impact due to establishment of a regulatory asset. within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. within Depreciation, depletion and amortization on the accompanying Consolidated ______of operations at the time of settlement for our non- liability and the recorded amount is recognized as a gain or loss in the results regulated operations, other than Oil and Gas. For the Oil and Gas segment, dif of oil and gas properties and depleted pursuant to recorded amount are generally reflected as adjustments to the capitalized cost our use of the full cost method. Goodwill and Intangible Intangible and Goodwill of an indicator upon are reviewed values the carrying but not amortized lives are indefinite assets with and intangible Goodwill or at least annually impairment W perform this annual review of goodwill and indefinite lived intangible assets as of Nov lived intangible goodwill and indefinite annual review of perform this indicators arise). impairment methodology discounted cash flow operating cost escalation future growth rates, cash flow projections, several critical assumptions, including required the input of the cost of debt level of success in regulatory rate proceedings, a risk-adjusted discount rate, timing and rates, rates of return, long-term earnings and mer and equity capital, and and four regulated gas from the acquisition of one regulated electric and Gas Utilities primarily arose Goodwill at our Electric utilities in the percent the regulatory the regulated gas utility business, considering stable, long-lived cash flows of the value of the relatively at our electric utility cash flow and rate base growth opportunities growth potential and the long-lived environment and market balances were as follows (in thousands): in Colorado. Goodwill assets for the years ended Dec. 31, were as follows (in thousands): assets for the years ended Dec. 31, were Our intangible assets represent easements, rights-of-way and trademarks and are amortized using a straight-line method based rights-of-way and trademarks and are amortized using a straight-line method Our intangible assets represent easements, on estimated useful lives. 128 |10K FORM 10K Oil andGasSegment: V impacting theavailabilityofobservablepricinginputs. observable suchasthetimebetweenvaluationdateanddeliveryofatransactionbecomesshorter availability ofobservablepricinginputs. such asasignificantdecreaseinthefrequencyandvolumewhichinstrumentistraded,negativelyimpacting T reporting periodforallofourfinancialinstruments. af measurement. Ourassessmentofthesignificanceaparticularinputtofairvaluemeasurementrequiresjudgment andmay Assets andliabilitiesareclassifiedintheirentiretybasedonthelowestlevelofinputthatissignificanttofairvalue use inpricingtheassetorliability reflect management’ Level 3 means. asset orliabilityandinputsthatarederivedprincipallyfromcorroboratedbyobservablemarketdatacorrelationother identical orsimilarassetsliabilitiesinmarketsthatarenotactive,inputsotherthanquotedpricesobservableforthe Level 2 derivatives. unrestricted assetsorliabilities. Level 1 Assets andliabilitiesareclassifieddisclosedinoneofthefollowingfairvaluecategories: Derivative FinancialInstruments Fair Utilities Segment: ransfers intoLevel3,ifany aluation MethodologiesforDerivatives fect theplacementwithinfairvaluehierarchylevels. • • •
V alue Measur current forwardpricestriphedgedforthesamequantityanddatediscountedbasedonthree-monthLIBOR. The commoditybasisswapsfortheOilandGassegmentarevaluedundermarketapproachusinginstrument’ timing. puts. Fairvaluewasderivedusingquotedpricesfromthirdpartybrokersforsimilarinstrumentsastoquantityand The commodityoptioncontractsfortheOilandGassegmentarevaluedundermarketapproachincludecalls and independent thirdpartymarketparticipantsincetheseinstruments arenottradedonanexchange. Level 3assetsandliabilities,fairvaluewasderivedusing average pricequotesfromtheOTCcontractbrokerandan value wasderivedusingbrokerquotesvalidatedbytheChicago MercantileExchangepricingforsimilarinstruments.For and basisswaps(Level2)OTC3) for naturalgascontracts.ForLevel2assetsandliabilities,fair The commoditycontractsfortheUtilities,valuedusing marketapproach,includeexchange-tradedfutures,options utilize observableinputswhichsupportLevel2disclosure. —Pricinginputsincludesignificantthataregenerallylessobservablefromobjectivesources. —Pricinginputsincludequotedpricesforidenticalorsimilarassetsandliabilitiesinactivemarkets, —Unadjustedquotedpricesavailableinactivemarketsthatareaccessibleatthemeasurementdateforidentical The pricesarethenvalidatedthroughthirdpartysourcesandthereforesupportLevel2disclosure. ements s bestestimateoffairvalueusingitsownassumptionsabouttheamarketparticipantwould , occurwhensignificantinputsusedtovaluethederivativeinstrumentsbecomelessobservable This levelprimarilyconsistsoffinancialinstrumentssuchasexchange-tradedsecuritiesorlisted . T ransfers outofLevel3,ifany W e recordtransfers,ifnecessary 128 , occurwhenthesignificantinputsbecomemore , betweenlevelsattheendof , positively These inputs W s e FORM 10K , 10K | 129 The When the fective , the ef s fair value be recognized s fair value be recognized . Each Consolidated Balance . Each Consolidated e establish fair value by obtaining price quotes price quotes obtaining value by fair e establish fsetting of fair value amounts recognized for the fsetting of fair value amounts recognized W fsetting unrealized loss or gain on the hedged item fsetting unrealized loss or gain on the hedged The remaining gain or loss on the derivative instrument, if any The remaining gain or loss on the derivative 129 considers the fair value of the interest rate swap and the probability of and the probability interest rate swap the fair value of the considers A fective interest method over the estimated useful life of the related debt. fective interest method over the estimated fects earnings. The CV 9. Accounting standards also permit of . component. component. A Activities fset exists. fsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty for cash collateral with the same counterparty positions with fair value amounts fsetting of net derivative fset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master fset exists, accounting standards permit ed Financing Costs fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains service that a nationally recognized validated by utilizing is then obtained from the counterparty fair value swap for the interest rate addition, the fair value instrument. In fair value for the same inputs to compute observable includes a CV derivatives utilize observable inputs component, we of a default contract. For the probability on the life of the default based spread curve that if available, or a generic credit default disclosure by using our credit default spread, supporting Level 2 credit ratings. takes into account our directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. for the term of the LIBOR curve the floating three-month which are based on the counterparty directly from The interest rate swaps are valued using the market valuation approach. approach. market valuation using the valued swaps are rate The interest • e utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each consist of an agreement between two parties who have multiple contracts with e utilize master netting agreements which Litigation liabilities, including potential settlements, are recorded when it is both probable that a liability or settlement has been Litigation liabilities, including potential settlements, are recorded when it is both litigation are expensed as incurred. incurred, and the amount can be reasonably estimated. Legal costs related to ongoing better estimate than any other amount, we record a When a range of the probable loss exists and no amount within the range is a at issue is not both probable and reasonably loss contingency at the minimum amount in the range. If the loss contingency for any developments that would make estimable, we do not establish an accrual and the matter will continue to be monitored the loss contingency both probable and reasonably estimable. Legal Costs W of all contracts in the event of default on or termination of any one contract. other that provide for the net settlement netting agreement between counterparties. incurred, development and acquisition costs According to accounting standards for business combinations, we expense, when construction of a project. Expensed associated with corporate development activities prior to acquiring or beginning Consolidated Statements of Income. development costs are included in Other operating expenses on the accompanying Additional information is included in Note Additional information Derivatives and Hedging on the balance sheet as that derivative instruments be recorded for derivatives and hedging require The accounting standards changes in the derivative instrument’ measured at its fair value, and that either an asset or liability are met and designated accordingly unless specific hedge accounting criteria currently in earnings Sheet reflects the of when a legal right of of hedging require that the unrealized gains or losses on a derivative instrument Accounting standards for derivatives and hedging instrument as well as the of designated and qualifying as a fair value currently in earnings in the same accounting period. Conversely attributable to the hedged risk be recognized is recognized currently in earnings. right of of cash collateral against fair value amounts recognized for derivative instruments right to reclaim, or the obligation to return, executed with the same counterparty Deferr using the ef Deferred financing costs are amortized Development Costs portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument a derivative instrument designated and qualifying as a cash flow hedging instrument portion of the unrealized gain or loss on or periods comprehensive income and be reclassified into earnings in the same period must be reported as a component of other af during which the hedged forecasted transaction Corporate Segment: Corporate 130 |10K FORM 10K Regulatory assetsrepresentitemsweexpecttorecoverfrom customersthroughprobablefuturerates. (f) (e) (d) (c) (b) (a) ______W could bematerial. standards forregulatedoperations,theaccountingimpacttouscouldbeanextraordinarynon-cashchar described below Our regulatoryassetsrepresentamountsforwhichwewillrecoverthecost,butgenerallyarenotallowedareturn,exceptas these accountingstandardsmaynolongerapplywhichwouldrequirenetassetstobechar used byournon-regulatedbusinesses.Ifraterecoverybecomesunlikelyoruncertainduetocompetitionregulatoryaction, generally subjecttotheUniformSystemof principles followedbythevariousstateandfederalagenciesregulatingutilities. Our UtilitiesGroupfollowsaccountingstandardsforregulatedoperationsandreflectstheef Regulatory Regulatory liabilities Regulatory assets Other regulatoryliabilities Cost ofremoval Employee benefitplans Deferred ener Other regulatoryassets Flow throughaccounting Renewable ener Bond issuecost Asset retirementobligations Environmental Employee benefitplans AFUDC Deferred gascostadjustmentsandpricederivatives Deferred ener e hadthefollowingregulatoryassetsandliabilities(inthousands): amortized asapprovedbythe appropriatestatecommission. recovered orrefundedinfuture rates.Deferredener electricity deliveredtoourelectric utilitycustomersthatiseitherhigherorlowerthanthe currentratesandwillbe Deferred Ener Approximately Approximately In additiontorecoveryofcosts,weareallowedareturnonapproximately In additiontorecoveryofcosts,weareallowedareturnonapproximately In additiontorecoveryofcosts,weareallowedaratereturn. Recovery ofcosts,butnotallowedaratereturn. (b) Accounting gy andgascosts gy andfuelcostadjustments-current . Intheeventwedeterminethatourregulatednetassetsnolongermeetcriteriaforfollowingaccounting (a) (a) gy standardadjustment (a) gy andFuelCost $2.6 million $13 million (a) (e) (c) (d) (f) isincludedinourratebasecalculationsasareductiontobase. isincludedinourratebasecalculationsasareductiontobase. (a) (a) Adjustments -Deferredener (a) Accounts oftheFERC. (a) gy andfuelcostadjustments are recordedandrecoveredor (a) 130 gy andfuelcostadjustmentsrepresenttheof These accountingpoliciesdif $5.4 million $25 million subject toapproval Amortization Maximum (inyears) 13 45 25 44 13 15 35 24 44 . 7 1 1 5 . The accountingpoliciesfollowedare fects ofthenumerousrate-making $ $ $ $ Dec. 31,2013 ged tocurrentincomeorOCI. fer insomerespectsfromthose As of 120,156 162,648 ge tooperations,which 67,059 12,315 12,366 16,775 64,970 34,431 11,708 10,546 20,916 14,186 1,800 9,047 3,419 3,266 $ $ $ $ Dec. 31,2012 As of 115,521 141,284 219,393 12,416 20,741 16,005 53,526 59,362 21,091 10,006 16,620 19,484 1,792 7,305 3,561 3,247 FORM 10K 10K | 131 ,
A s action, ’ ference for ransaction. T . Our Gas fect of the , if refinanced, provisions that that provisions Aquila These incentives are Any remaining recovery , respectively -recovery of purchased power 7 for additional details. The amortization of this asset is o the extent that gas costs are that gas costs are o the extent fects of certain tax items are T ference for tax purposes with the tax ference for tax purposes is based on forecasts of the upcoming gas forecasts of the upcoming is based on bills. This regulatory asset is a temporary dif This regulatory asset gy standard adjustment is associated with incentives gy standard adjustment is associated with -recovered costs. -recovered The GCA gy equipment at their location. 131 - Our regulated gas utilities have GCA have gas utilities regulated - Our Accounting standards for income taxes specifically address for income taxes specifically address Accounting standards fect has been grossed-up to account for the revenue requirement ged on customers’ gy costs and gas costs related to over -recovered or over -recovered The renewable ener - AFUDC is considered a permanent dif AFUDC is considered - Deferred ener Asset retirement obligations represent the estimated recoverable costs for legal Asset retirement obligations represent the ferences reverse. - Adjustment - Under flow-through accounting, the income tax ef - Under flow-through accounting, the income Employee benefit plans represent the cumulative excess of pension and retiree - Employee benefit plans represent the cumulative excess of pension and retiree - Employee benefit plans include the unrecognized prior service costs and net actuarial plans include the unrecognized prior service - Employee benefit -recovered, they are recorded as a regulatory asset or liability as a regulatory asset they are recorded -recovered, Adjustment and Gas Price Derivatives Gas Price and Adjustment Cost of removal represents the estimated cumulative net provisions for future removal costs - Cost of removal represents the estimated cumulative net provisions for future gy Standard - Environmental is associated with manufactured gas plant sites. - Environmental is associated with manufactured , and require a gross-up of such amounts to reflect the revenue requirement associated with a rate- of such amounts to reflect the revenue , and require a gross-up Accounting gy and Gas Costs This regulatory treatment was applied to the tax benefit generated by repair costs that were previously This regulatory treatment was applied to underlying exposure to fluctuations in gas prices. in gas prices. exposure to fluctuations underlying The equity component of The equity component - fset by recognition of insurance proceeds and settlements with other third parties. fset by recognition of insurance proceeds -recovered or over -recovered under to record the full pension and post- adjustment required under accounting for compensation - defined benefit plans, retirement benefit obligations. Such income tax ef healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for healthcare costs recovered in rates over pension expense recorded in accordance the income tax ef compensation - retirement benefits. In addition, this regulatory liability includes Cost of Removal included in depreciation expense for which there is no legal obligation for removal. Employee Benefit Plans aspect of a rate regulated environment. Deferred Ener costs and recovery or refund of prior under recovery or refund costs and utility commissions. with state based on market forecasts of future gas costs periodic estimates Utilities file liability must be recognized. which a deferred tax of a tangible long-lived asset. See Note obligations associated with the retirement over the life of the new issue. install renewable ener for our Colorado Electric customers to Flow-Through transmission and natural gas costs. - Bond issue costs are recovered over the remaining life of the original issue or Bond Issue Costs - Bond issue costs are recovered over the Renewable Ener Asset Retirement Obligations AFUDC-equity regulated environment. Environmental Employee Benefit Plans assets rather post-retirement benefit plans in regulatory our defined benefit pension plans and loss associated with costs being amortized from the other comprehensive income, including than in accumulated allow them to pass the cost of gas on to their customers. In addition, as allowed or required by state utility state utility required by or as allowed In addition, customers. on to their of gas the cost them to pass allow reduce our options to and gas futures natural certain exchange-traded into have entered we commissions, customers’ allowed by regulators. If, based on a regulator through to customers as prescribed or benefit being flowed treatment taxes payable represented by this flow-through will recover the future increase in it is probable the utility increase, a regulatory asset is recognized. through a rate revenue first of rider char recovered over time with an additional in the year in which the tax benefits are realized and result in lower reflected in our cost of service for the customer utility rates. settlement that was reached with respect to Black Hills Power in 2010. In capitalized for tax purposes in a rate case was less than it would have been absent the flow-through treatment. this instance, the agreed upon rate increase payable will be recovered from regulatory asset was established to reflect that future increases in income taxes customers as the temporary dif AFUDC Deferred Gas Cost Gas Cost Deferred will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board will be requested in future rate filings. and therefore, the recovery period is unknown. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Regulatory liabilities represent items we expect to refund to customers through 132 |10K FORM 10K have beenanti-dilutive(inthousands): The followingoutstandingsecuritieswerenotincludedin the computationofdilutedearningspershareastheiref A due tooutstandingstockoptions,restrictedandperformancesharesunderourequitycompensationplans. share iscomputedbyincludingalldilutivecommonsharesoutstandingduringeachyear discontinued operationsbytheweightedaveragenumberofcommonsharesoutstandingduringeachyear Basic earningspersharefromcontinuinganddiscontinuedoperationsiscomputedbydividingIncome(loss) or Earnings per Consolidated BalanceSheets.SeeNote income taxes. W the ConsolidatedStatementsofIncome. W the usefullivesofrelatedproperty regulated businessesistoapplythedeferralmethodwherebycreditamortizedasareductionofincometaxexpenseover expense intheyeartheyqualify jurisdictions. Undertheflow-throughmethod,investmenttaxcreditsarereflectedinnetincomeasareductionto It isourpolicytoapplytheflow-throughmethodofaccountingforinvestmenttaxcreditsasallowedbyrate-regulated based onthenatureofrelatedassetsandliabilities. they arereportedinthefinancialstatements. the incometaxlawthateitherrequireorpermitcertainitemstobereportedonreturninadif and liabilitiesaswelloperatinglosstaxcreditcarryforwards.Suchtemporarydif currently enactedincometaxrates,toreflecttheef W computations oftaxableincomeorloss. it wereaseparatetaxpayerandconsolidatingadjustmentsareallocatedtothesubsidiariesbasedoncompany The Companyanditssubsidiariesfileconsolidatedfederalincometaxreturns.Eachpayingentityrecordstaxesasif Income share Anti-dilutive sharesexcluded fromcomputationofearnings(loss)per Other Equity compensation Income (loss)fromcontinuingoperations,pershare-Diluted Weighted averageshares-diluted Dilutive effectof: Weighted averageshares-basic Income (loss)fromcontinuingoperations reconciliationofshareamountsusedtocomputeearnings(loss)perisasfollows(inthousands): Other Equity compensation e accountforuncertaintyinincometaxesrecognizedthefinancialstatementsaccordancewithaccountingstandards for e recognizeinterestincomeorexpenseandpenaltiesrelatedtotaxmattersinIncome(expense)benefiton e usetheliabilitymethodinaccountingforincometaxes.Undermethod,deferredtaxesarerecognizedat T axes Shar The unrecognizedtaxbenefitisclassifiedinOtherdeferredcreditsandotherliabilitiesontheaccompanying e ofCommonStock . Another acceptableaccountingmethodandanexceptiontothisgeneralpolicycurrentlyinour . 14 foradditionalinformation. W e classifydeferredtaxassetsandliabilitiesintocurrentnon-currentamounts fect oftemporarydif 132 $ $ Dec. 31,2013 ferences betweenthefinancialandtaxbasisofassets 115,846 Dec. 31,2013 44,419 44,163 2.61 256 — $ $ . Dilutedcommonsharesareprimarily ferences aretheresultofprovisionsin Dec. 31,2012 22 — 22 Dec. 31,2012 44,073 43,820 88,505 2.01 250 3 . Dilutedearningsper 163 163 — $ $ ferent periodthan Dec. 31,2011 Dec. 31,2011 fect would 40,081 39,864 40,365 1.01 141 141 214 — 3 FORM 10K 10K | 133 , fective on a ASU fective Swap Additionally ASU 2013-10 ferent benchmark fective Date for 1-05 requires fects all companies that ASU 201 The adoption of this standard did AOCI to expand the disclosure ASU 2013-02 requires disclosure (1) of Accounting Purposes, Accounting Purposes, 1-12 indefinitely deferred the AOCI and into net income in their ASU 2013-02 s netting arrangements and/or rights of fective for new or re-designated hedging fective for new or re-designated AOCI. 1-05 and Deferral of the Ef ASB chose not to reinstate the reclassification ASU 201 for additional information. Note 21 for additional gy Inc. See 1, Clarifying the Scope of Disclosures about 1, Clarifying the Scope The revised disclosure guidance was ef Also, items that are reclassified from other Also, items that are reclassified from other ASC 210, Balance Sheet, related to the existing ASC 210, Balance Sheet, related to the 1-1 The adoption of this standard did not have an impact The adoption of this standard did not have 1-12. ASU 201 fset in the balance sheet (i.e., presented on a net basis) or fset in the balance sheet (i.e., presented Accumulated Other Comprehensive Income in Accumulated Other Comprehensive Income ASU 201 The revised disclosure guidance af ASU 201 133 ASU 2013-02 in February 2013. fective for interim and annual periods beginning after Dec. 15, and IFRS. ASB issued The amendment also removed the restriction on using dif The amendment also fected net income line item and (3) of cross references to other disclosures 1, F Assets and Liabilities, Assets and Liabilities, Accumulated Other Comprehensive Income, fective for fiscal years, and interim periods within those years, beginning after Dec. 15, fective for fiscal years, and interim periods 1-05 but instead issued fsetting ASU 2013-01 fsetting financial assets and liabilities to enhance current disclosures, as well as to improve fsetting financial assets and liabilities to fective Swap Rate as a Benchmark Interest Rate for Hedge a Benchmark Interest Rate for Hedge fective Swap Rate as ASU 201 , indirect corporate costs previously allocated to a disposal group cannot be reclassified to be reclassified a disposal group cannot allocated to costs previously , indirect corporate Assets of discontinued operations and Liabilities of discontinued operations on the accompanying on the accompanying of discontinued operations and Liabilities discontinued operations Assets of ASB issued revised accounting guidance to amend ASB issued revised accounting guidance The adoption had no impact on our consolidated financial position, results of operations or cash flows. impact on our consolidated financial The adoption had no ASB issued new disclosure requirements for items reclassified out of 1-05 requiring the presentation of reclassification adjustments on the face of the financial statements for 1-05 requiring the presentation of reclassification adjustments on the face of the 1-12 The new disclosure requirements are ef Accounting Standards Accounting ASB issued an amendment to accounting for derivatives and hedges to permit the Fed Funds Ef to accounting for derivatives and ASB issued an amendment 1, the F ASC 220, Comprehensive Income, for presentation of changes in fect of the reclassification on each af , consistency and transparency of reporting. It amends existing guidance by allowing only two options for , consistency and transparency of reporting. ASU 201 Amounts Reclassified Out of ASU 201 Assets and Liabilities, Assets and Liabilities, Adopted , the ef The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. The adoption of this standard did not have an impact on our financial position, 1-05 and 1, with early adoption permitted. In Dec. 201 fsetting fset associated with its financial instruments and/or derivative instruments. fset associated with its financial instruments ASB issued an accounting standards update amending accounting standards for comprehensive income to improve the amending accounting standards for comprehensive income to improve the ASB issued an accounting standards update 2012. that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net that provide additional detail for components of other comprehensive income or as a separate disclosure in the notes to the income. Disclosures are required either on the face of the statements of income financial statements. requirements in out of changes in components of other comprehensive income, (2) for items reclassified entirety in accordance with GAAP in accordance In February 2013, the F discontinued operations. discontinued Consolidated Balance Sheets included the assets and liabilities of Enserco Ener and liabilities of Enserco included the assets Balance Sheets Consolidated Reporting of Recently In July 2013, the F F comparability and other comprehensive income: (1) in a single continuous financial statement, presenting the components of net income (2) in two separate but consecutive financial statements, consisting of an income statement of comprehensive income or of other comprehensive income. statement followed by a separate statement be presented on the face of the financial statements. comprehensive income to net income must Other Comprehensive Income: Presentation of Comprehensive Income, Other Comprehensive Income: Presentation of Items Out of Amendments to the Presentation of Reclassification 201 In December 201 Balance Sheet: Disclosure about Of Balance Sheet: Disclosure Of F items reclassified from other comprehensive income to net income. Ultimately Inclusion of the Fed Funds Ef Inclusion of the Fed accounting purposes ef U.S. benchmark interest rate for hedge Rate to be used as a into on or after July 17, 2013. relationships entered rates for similar hedges. disclosure requirements for of under GAAP comparability of balance sheets prepared instruments that are either of have financial instruments and derivative and/or similar arrangement. In addition, the revised guidance requires that certain subject to an enforceable master netting are made with respect to a company’ enhanced quantitative and qualitative disclosures of retrospective application, and it was ef 201 provisions of adjustment requirements in not have an impact on our financial position, results of operations or cash flows. Assets of discontinued operations are recorded at the lower of their carrying amount or fair value less cost to sell. cost to sell. less or fair value amount carrying lower of their at the are recorded operations of discontinued Assets Discontinued Operations Discontinued retrospective basis for interim and annual periods beginning Jan. 1, 2013. retrospective basis for interim and annual or cash flows. on our financial position, results of operations 134 |10K FORM 10K date indicatesnomaterialimpacttoourconsolidatedfinancial statements. regulations in2014.Proceduralguidanceisexpectedfrom IRSinearly2014tofacilitateimplementation. 1, 2014,withearlyadoptionpermitted. should betakenintoaccountintheperiodofadoption.Ingeneral,suchregulationsapplytotaxyearsbeginningonor afterJan. acquire, produce,orimprovetangibleproperty In September2013,theU.S. Final statements. enhanced disclosuresinthenotestofinancialstatements,butwillnothaveanyotherimpactonourconsolidated disclosure requirementsareef resulting fromjointandseveralliabilityarrangementsincludingdisclosureofthenatureamountobligations. In March2013,theF the ReportingDate, Obligations ResultingfromJointandSeveralLiability The adoptionofthisstandardisnotexpectedtohaveanimpactonourfinancialposition,resultsoperationsorcash flows. and interimperiodswithinthoseyearsshouldbeappliedtoallunrecognizedtaxbenefitsthatexistasoftheef credit carryforwardexceptundercertainconditions. benefit, inthefinancialstatementsasareductiontodeferredtaxassetforanNOL current GAAP The objectiveinissuingthisamendmentistoeliminatediversitypracticeresultingfromalackofguidanceon topicin presentation ofanunrecognizedtaxbenefitwhenNOL In July2013,theF Carryforward Exists, Presentation ofanUnrecognized Recently Issued completed duediligenceef that filereportswiththeSECanduseconflictmineralstoreportsupplychainsourcinginformationonanannualbasis. manufacture productsthatcontaincertainmineralsandmetals,knownasconflictminerals. In swaps havebeenconvertedtoexchange-tradedfuturescontracts,whicharesubjectmar entities forcertainswaptransactionsweenterinto.Inaddition,manyofthewhichwerepreviouslyclassifiedas unregulated. T In July2010,thePresidentofUnitedStatessignedintolawcomprehensivefinancialreformlegislationunderDodd-Frank. Dodd-Frank itle August 2012,underDodd-Frank,theSECadoptednewrequirementsforcompaniesthatmanufactureorcontractto VII ofDodd-Frankef T angible PersonalPropertyRegulations,IRS W As aresultofDodd-FrankregulationspromulgatedbytheCFTC,wemayberequiredtopostcollateralclearing . Undertheamendment,anentitymustpresentunrecognizedtaxbenefit,oraportionof all StreetReformandConsumerProtection Accounting Pr ASB issuedanamendmenttoaccountingforincometaxeswhichprovidesguidanceonfinancialstatement ASU 2013-04 ASB issuednewdisclosurerequirementsforrecognition,measurementandofobligations ASU 2013-1 fectively regulatesmanyderivativetransactionsintheUnitedStatesthatwerepreviously forts in2013,andwedonotbelievethatourproductscontainconflictmineralsasdefinedbytherule. T fective forinterimandannualperiodsbeginningafterDec.15,2013. reasury issuedfinalregulationsaddressingthetaxconsequencesassociatedwithamountspaidto onouncements andLegislation T 1 ax Benefit W e expectthatimplementationofmost,ifnotall,theprovisions ofthefinal When aNetOperatingLossCarryforward,Similar . The regulationshavetheef T The amendmentisef reasury Decision9636 Arrangements for carryforward,asimilartaxloss,orcreditcarryforwardexists. Act, SECFinalRuleNo.33-9286,33-9338,34-67717,and34-67716 134 Which the fective forfiscalyearsbeginningafterDec.15,2013, fect ofachangeinlawandasresulttheimpact carryforward,asimilartaxloss,or T otal Amount oftheObligationisFixedat The finalrulerequiresallissuers gin postingrequirements. T The amendmentrequires ax Loss,ora Analysis performedto T fective date. ax Credit The new W e FORM 10K 10K | 135 37 57 56 22 32 60 20 65 65 65 Maximum Maximum 3 Lives (in years) 37 53 41 16 Lives ( in years) Lives ( in 32 20 25 40 15 Minimum Minimum
between Colorado Electric and Black 37 54 46 19 32 22 19 45 50 44 A Average Average Weighted (in years) Weighted (in years) Useful Life Useful Life 2012 2012 on Dec. 31, 2031. 13 A 17 years remaining. 6,305 4,870 18,071 68,856 68,530 48,008 474,998 561,938 568,243 499,713 260,874 137,584 439,772 959,636 234,279 631,654 2,228,897 2,276,905 1,837,133 Property, Plant and Property, Plant and Equipment Equipment $ $ $ $ $ 37 54 46 19 20 32 22 45 50 44 135 Average Average Weighted (in years) Weighted (in years) Useful Life Useful Life 2013 2013 13 4,870 9,417 24,984 85,841 84,679 261,441 138,263 203,760 507,318 542,894 472,970 618,156 627,573 951,138 238,542 666,589 2,260,843 2,464,603 1,991,633 Property, Property, Plant and Plant and Equipment Equipment $ $ $ $ $ (b) AND EQUIPMENT AND
(a) The capital lease ends in conjunction with the expiration of the PP The capital lease ends in conjunction with the , PLANT . TY PROPER , plant and equipment at Dec. 31 consisted of the following (dollars in thousands): following (dollars 31 consisted of the equipment at Dec. , plant and Hills Colorado IPP Capital lease - plant in service represents the assets accounted for as a capital lease under the PP Capital lease - plant in service represents the The plant acquisition adjustment is included in rate base and is being recovered with The plant acquisition adjustment is included Total electric plant in service Total electric plant Total gas plant in service Total gas plant General Capital lease - plant in service Construction work in progress Electric plant net of accumulated depreciation and amortization Gas transmission Gas distribution General Construction work in progress Gas plant net of accumulated depreciation and amortization Production Production Electric transmission Electric distribution Plant acquisition adjustment Gas Utilities Electric Utilities Less accumulated depreciation and amortization Less accumulated depreciation and amortization Utilities Group Gas plant: Electric plant: ______(a) (b) (2) Property 136 |10K FORM 10K Oil andGas Coal Mining Power Generation Non-regulated Energy Oil andGas Coal Mining Power Generation Non-regulated Energy Corporate (a) ______(a) ______Corporate dif Accumulated depreciation,depletionandamortizationatCorporate reflectstheeliminationofcapitalleaseaccumulateddepreciation dif Accumulated depreciation,depletionandamortizationatCorporatereflectstheeliminationofcapitalleaseaccumulateddepreciation 2012 2013 ference betweenColoradoElectricandIPP ference betweenColoradoElectricandIPP 2012 2013 $ $ Equipment Equipment Plant and Property, Plant and Property, 5,498 $ $ Equipment $ $ Equipment 368 Plant and Property, 1,144,477 Plant and Property, 1,073,035 852,384 149,067 143,026 785,594 148,045 139,396 $ $ Construction Construction Progress Progress Work in Work in $ $ Construction $ $ Construction 3,875 5,647 Progress Work in Progress Work in 11,647 10,491 1,156 8,346 1,323 7,023 $ $ Equipment Equipment Plant and Plant and Property Property — — Total Total 11,145 4,243 $ $ Equipment . . $ $ Equipment Plant and 1,156,124 Property Plant and 1,081,381 Property Total 852,384 150,223 153,517 Total 785,594 155,068 140,719 $ $ Amortization Amortization Depletion and Depletion and 136 Depreciation, Depreciation, Accumulated Accumulated Less Less $ $ Depreciation, Accumulated Amortization $ $ Depreciation, Accumulated Amortization Depletion Depletion (3,210 (1,956 Less and Less 714,709 585,334 and 681,677 562,926 43,069 86,306 38,541 80,210 (a) (a) ) ) $ $ Equipment Equipment Plant and Property, Plant and Property, $ $ Equipment Net Net $ $ Equipment Plant and 14,355 Property, Plant and Property, 6,199 441,415 110,448 267,050 399,704 102,178 222,668 Net 63,917 Net 74,858 Weighted Weighted Average Average Useful Useful Life Life Weighted Average Weighted 6 Average 6 Useful Useful Life Life 36 24 14 35 24 14 Lives (inyears) Lives (inyears) Lives (inyears) Minimum Minimum Lives (inyears) Minimum Minimum 2 2 2 3 2 2 3 2 Maximum Maximum Maximum Maximum 30 40 25 59 40 25 59 30 FORM 10K 10K | 137 841 e 4,741 50,595 28,432 10,593 W . . Our share . Our share Depreciation Accumulated yodak Plant. W $ $ $ $ $ — — 192 713 1,412 WRDC, supplies , This coal supply agreement is This coal supply agreement e retain responsibility for plant ygen III for the life of the plant. estern and Eastern transmission W est. Black Hills Power is W The total transfer capacity of the . W W in Progress . MDU and the City of Gillette each Construction Work $ $ $ $ $ region. AltaGas owns the remaining undivided AltaGas owns the remaining undivided s coal reserves. s capacity and is committed to pay its s capacity and is committed 19,648 18,590 109,800 106,489 131,468 WRDC’ Plant in Service yodak Plant’ $ $ $ $ $ ind Project while W W 137 e retain responsibility for operations of the wind farm. e retain responsibility for operations of yodak Plant, a coal-fired electric generating station located in electric generating station located yodak Plant, a coal-fired W W . ygen I plant while MEAN owns the remaining ownership percentage. yodak Plant, our Coal Mining subsidiary yodak Plant, our Coal WECC region and the MAPP W W AC-DC-AC transmission tie. Basin Electric owns the remaining tie. Basin Electric owns the remaining AC-DC-AC transmission ygen III coal-fired generation facility ygen III and are obligated to make payments for costs associated with ygen III and are obligated to make payments W interest in, and is the operator of, the Converter Station Site and South Rapid operator of, the Converter Station Site interest in, and is the W of the est to East and 200 megawatts from East to est to East and 200 megawatts from East yodak Plant under a separate long-term agreement. yodak Plant under a W interest in the W of the of the Busch Ranch ACILITIES 50 percent The transmission tie provides an interconnection between the The transmission tie provides an interconnection yoming. PacifiCorp owns the remaining ownership percentage and operates the owns the remaining ownership percentage yoming. PacifiCorp W , yoming owns 76.5 percent OWNED F OWNED W s share of the coal to the s share of the coal to Y JOINTL Black Hills Power owns a 20 percent Black Hills Power owns Campbell County Black Hills Power receives its proportionate share of the Black Hills Power receives Our Coal Mining subsidiary supplies coal to retain responsibility for plant operations. Black Hills administrative services and their proportionate share of the costs of operating the plant for the life of the facility administrative services and their proportionate administrative services, plant operations MEAN is obligated to make payments for its share of the costs associated with facility and coal supply provided by our Coal Mining subsidiary during the life of the proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying and maintenance expenses. In addition of its additions, replacements and operating proportionate share coal for its share of the Black Hills Power with PacifiCorp’ of on and a security interest in some collateralized by a mortgage owns a 35 percent Black Hills Power also (the transmission tie), an City Interconnection ownership percentage. both the grids, which provides us with access to tie is 400 megawatts - 200 megawatts of the additions and replacements to and operating and maintenance expenses committed to pay its proportionate share of the transmission tie. Black Hills Power owns 52 percent owns an undivided ownership interest in Colorado Electric owns of payments for costs associated with their proportionate share of the costs ownership interest and is obligated to make the facility operating the wind project for the life of operations. . Our share of direct expenses for the jointly-owned facility is included in the corresponding categories of operating . Our share of direct expenses for the jointly-owned • • • • • Wyodak Plant Transmission Tie Wygen I Wygen III Busch Ranch Wind Project (3) Our consolidated financial statements include our share of several jointly-owned utility facilities as described below facilities as described utility share of several jointly-owned include our financial statements Our consolidated Utility Plant Statements of in the Consolidated operating expenses categories of in the appropriate expenses are reflected of the facilities facilities. in the jointly-owned for financing its investment is responsible owner of the facility Income. Each expenses in the accompanying Consolidated Statements of Income. Each of the respective owners is responsible for providing Statements of Income. Each of the respective owners is responsible for expenses in the accompanying Consolidated its own financing. Our consolidated financial statements include our share of a jointly-owned non-regulated power generation facility as described our share of a jointly-owned non-regulated power generation facility as Our consolidated financial statements include below Non-Regulated Plants , our interests in jointly-owned generating facilities and transmission systems were (in thousands): At Dec. 31, 2013, our interests in jointly-owned generating facilities and transmission systems 138 |10K FORM 10K (a) ______(a) ______Segment informationwasasfollows(inthousands): see Note21. have notbeenclassifiedasdiscontinuedoperationsreclassifiedtoourCorporatesegment.Forfurtherinformation of thissegmentasdiscontinuedoperations.Indirectcorporatecostsandinter discontinued operations.Forcomparativepurposes,allpriorperiodspresentedhavebeenrestatedtoreflectthereclassification On Feb.29,2012,wesoldourEner States. groups duetodif Our reportablesegmentsarebasedonourmethodofinternalreporting,whichgenerallysegregatesthestrategicbusiness (4) Total capitalexpendituresandassetacquisitions Total capitalexpendituresofdiscontinuedoperations Total capitalexpendituresandassetacquisitionsofcontinuing operations Corporate Non-regulated Energy: Utilities: Capital Expendituresand Total assets Corporate Non-regulated Energy: Utilities: Total Assets(netofinter-companyeliminations)asDec.31, Oil andGas Coal Mining Gas Oil andGas Coal Mining Power Generation Gas Utilities Electric Utilities Power Generation Electric Includes accrualsforproperty The PP Electric underaccountingforacapitallease. Generation stationisaccountedforasacapitallease. BUSINESS SEGMENTSINFORMA (a) A underwhichBlackHillsColoradoIPP
ferences inproducts,servicesandregulation. (a) Asset , plantandequipment. Acquisitions gy Marketingsegment,Enserco,whichresultedinthissegmentbeingreclassifiedas (a) fortheyearsendedDec.31, providesgenerationtosupportColoradoElectriccustomersfromthePueblo TION As such,assetsownedbyourPowerGenerationsegmentarerecordedatColorado 138 All ofouroperationsandassetsarelocatedwithintheUnited -segment interestexpenserelatedtoEnsercothat $ $ $ $ 2013 2013 2,525,947 3,875,178 288,366 805,617 379,534 379,534 222,262 78,825 95,692 10,319 63,205 80,731 64,687 13,533 5,528 — $ $ $ $ 2012 2012 2,387,458 3,729,471 Airport 258,460 119,170 765,165 347,156 115,408 347,980 167,263 107,839 83,810 45,711 13,420 7,376 5,547 824 FORM 10K 10K | 139 — — 1,798 1,723 4,243 30,169 (61,608) 141,217 255,552 115,846 386,936 492,147 Total (111,788) 568,243 140,719 155,068 785,594 1,275,852 1,275,852 Airport 2,276,905 3,930,772 2012 $ $ — — — $ $ 218 (6,972) 84,250 (12,876) (41,869) (42,641) (76,724) (211,977) (112,489) (344,314) (344,314) 11,145 Eliminations 627,573 153,517 150,223 852,384 Inter-company $ $ 2,464,603 4,259,445 2013 — — 125 6,062 $ $ (7,778) 11,624 54,471 41,453 69,760 30,169 (85,195) 202,809 220,620 220,620 Corporate $ $ — — — — 108 f of deferred financing costs upon repayment of 3,545 1,639 (7,251) (4,212) (2,253) 21,770 40,365 54,884 54,884 Gas Oil and $ $ — — 10 — f of deferred financing costs and a make-whole provision (932) (641) 5,586 6,327 2,304 11,523 39,519 56,628 31,442 25,186 Coal Mining $ $ 1 — — — Consolidating Income Statement Consolidating Income 785 139 5,091 4,648 47,760 16,288 30,186 83,037 78,389 (11,080) (21,178) Power Generation $ $ As such, assets owned by our Power Generation segment are recorded for at by our Power Generation segment are recorded As such, assets owned — — — (60) 976 5). 76,772 26,381 32,707 provides generation to support Colorado Electric customers from the Pueblo support Colorado Electric customers from provides generation to Gas (19,747) (25,234) 126,073 310,463 539,689 539,689 Utilities $ $ — — 633 5,277 77,704 52,134 13,863 (25,834) (61,537) 133,595 159,961 294,048 665,308 651,445 Electric Utilities $ $ (a) (a) yoming Project Financing and Corporate includes a the write-of (a) W under which Black Hills Colorado IPP under which Black Hills A Generation station is accounted for as a capital lease. Generation station is accounted accounting for a capital lease. Colorado Electric under from early repayment of long-term debt (see Note Power Generation includes costs associated with interest rate swaps settled and write-of Black Hills The PP Operating income (loss) Income (loss) from continuing operations Total revenue Electric Utilities Electric Utilities Power Generation Gas Utilities Coal Mining Oil and Gas Depreciation, depletion and amortization Interest expense Gain on sale of operating assets Income tax benefit (expense) Operations and maintenance Other income (expense), net Fuel, purchased power and cost of natural gas sold Interest income Inter-company revenue Revenue Unrealized gain (loss) on interest rate swaps, net Utilities: Energy: Non-regulated Corporate and equipment Total property, plant Property, Plant and Equipment as of Dec. 31, as and Equipment Plant Property, Year ended Dec. 31, 2013 (a) ______(a) ______140 |10K FORM 10K (c) (b) (a) ______Revenue Year endedDec.31,2012 rate swaps,net Unrealized gain(loss)oninterest Interest expense amortization Depreciation, depletionand natural gassold Fuel, purchasedpowerandcostof Interest income Impairment oflong-livedassets Operations andmaintenance Inter Other income(expense),net Gain onsaleofoperatingassets Income taxbenefit(expense) Operating income(loss) Total revenue operations Income (loss)fromcontinuing Corporate includesamake-wholeprovisionfromearlyrepaymentoflong-termdebt(seeNote Oil andGasincludesaceilingtestimpairment(seeNote Oil andGasincludesgainonsaleofthe -company revenue (c)
(b) (a) $ $ Utilities Electric 610,732 131,721 626,966 273,474 146,527 (59,194) (30,264) 16,234 75,244 51,598 8,153 1,182 — — — W illiston Basinassets(seeNote $ $ Utilities 454,081 454,081 245,349 117,390 Gas (26,746) (14,313) 66,179 25,163 27,990 2,765 105 — — — — 12). $ $ Generation Power (15,452) 44,799 79,389 75,200 29,991 21,328 (8,721) 4,189 4,599 140 695 — — — — Consolidating IncomeStatement 7 $ $ Mining 21). Coal 57,778 31,968 25,810 13,060 42,553 2,165 1,168 2,616 5,626 (238) (85) — — — — $ $ Oil and (29,129) Gas 26,868 79,072 79,072 38,494 43,267 (4,539) (2,229) 1,927 (428) 604 207 — — — 5). $ $ Corporate 196,453 196,453 179,059 (92,650) 10,936 64,695 48,769 32,341 6,458 1,882 3,187 — — — — $ $ Inter-company Eliminations (319,855) (319,855) (111,757) (188,051) (12,864) (76,123) (49,921) (48,149) 85,209 (7,183) (131) — — — — $ $ 1,173,884 1,173,884 (113,610) Total 243,711 154,632 407,066 370,736 (29,129) (48,400) 26,868 88,505 1,882 1,957 2,965 — FORM 10K 10K | 141 — — 2,017 3,726 40,365 (91,383) (42,010) (18,224) Total 135,591 186,239 574,989 375,369 1,272,188 1,272,188 $ $ — — 767 268 (10,955) (14,832) (67,421) (47,135) (88,149) (46,552) 102,130 (267,349) (267,349) (174,908) Eliminations Inter-company $ $ 1 — 97 4,774 11,205 10,000 64,299 46,510 19,289 (93,314) (42,010) 192,250 192,250 170,947 Corporate $ $ 2 — — — — (216) 2,738 1,651 (5,896) (1,721) 35,690 79,808 79,808 41,380 Gas Oil and $ $ (9) — — — (424) 3,897 2,192 1,891 (8,395) 34,090 18,670 32,802 66,892 56,617 Coal Mining $ $ Consolidating Income Statement Income Consolidating — — — 141 4,199 4,059 1,529 1,094 3,011 (8,903) (1,644) 27,613 31,672 10,935 16,538 Power Generation $ $ — — — 217 5,645 24,307 76,336 34,169 Gas (31,621) (16,408) 554,584 554,584 331,961 121,980 Utilities $ $ — 481 (768) 13,396 52,475 14,794 47,691 (53,770) (23,271) 600,935 614,331 109,457 310,352 142,815 Electric Utilities $ $ (a)
-company revenue Electric Utilities includes gain on sale of assets to a related party which was eliminated in consolidation. Electric Utilities includes gain on sale of assets Total revenue Operating income (loss) Income (loss) from continuing operations Year ended Dec. 31, 2011 Year ended Depreciation, depletion and Depreciation, depletion amortization Revenue Inter Fuel, purchased power and cost of Fuel, purchased power natural gas sold Interest expense Unrealized gain (loss) on interest rate swaps, net Operations and maintenance Interest income Gain on sale of operating assets Gain on sale of operating Other income (expense), net Income tax benefit (expense) ______(a) 142 |10K FORM 10K (a) ______compliance withat Our debtsecuritiescontaincertain restrictivefinancialcovenants,allofwhichtheCompany anditssubsidiarieswerein Scheduled maturitiesoflong-termdebt,excludingamortization ofpremiumsordiscounts,forfutureyearsare(inthousands): Long-term debtoutstandingwasasfollows(dollarsinthousands)of: (5) (c) (b) Total long-termdebt Less currentmaturities Power Generation Electric Utilities Corporate Corporate termloandue2013 Corporate termloandue2015 Senior unsecurednotesdue2020 Senior unsecurednotesdue2014 Senior unsecurednotesdue2023 This debtrepaid.SeeDebt V V Pollution controlrevenuebondsdue2024 Industrial developmentrevenuebondsdue2021,variablerate First MortgageBondsdue2037 Black Hills First MortgageBondsdue2039 First MortgageBondsdue2032 Industrial developmentrevenuebondsdue2027,variablerate Series 94A ariable interestrates,basedonLIBORplusaspread. ariable interestrate. Unamortized discountonFirstMortgageBondsdue2039 Long-term debt,netofcurrentmaturities Total ElectricUtilities Total CorporateDebt LONG-TERM DEBT Debt,variablerate W yoming projectfinancing,variablerate Dec. 31,2013. T ransactions discussedbelow (b) (a)
(c) (a) Thereafter 2018 2017 2016 2015 2014 (a) . (c) (c) 142 $ $ $ $ $ $ March 1,2027 Sept. 30,2013 Aug. 15,2032 Nov. 20,2037 Nov. 30,2023 June 19,2015 May 15,2014 July 15,2020 Sept. 1,2021 Nov. 1,2039 Dec. 9,2016 June 1,2024 Oct. 1,2024 Due Date 1,122,055 275,000 Interest Rateat Dec. 31,2013 — — — — 5.88% 6.67% 5.35% 6.13% 7.23% 3.59% 0.11% 1.31% 9.00% 0.75% 0.11% 4.25% NA $ $ Dec. 31,2013 1,396,948 1,396,948 1,000,000 200,000 110,000 180,000 396,948 275,000 525,000 12,200 75,000 10,000 7,000 2,855 (107) — — — — $ $ Dec. 31,2012 1,042,850 200,000 110,000 180,000 938,877 103,973 100,000 396,944 550,000 250,000 12,200 75,000 95,906 10,000 7,000 2,855 (111) — — FORM 10K 10K | 143 — 33 76 31 70 462 167 $7.1 1,012 2011
The $ $ $ $ $ $ $ $ The proceeds — 33 76 31 57 462 167 1,037 2012 $100 million $ $ $ $ $ $ $ $ ; At Dec. 31, 2013, the ). . This repayment . 30, 2023. 86 33 76 31 57 635 167 years ended Dec. 31, 3,177 Nov 2013 Amortization Expense for the $ $ $ $ $ $ $ $ $64 million expiring on June 19, 2015. May 15, 2014. — — f. 618 736 664 gin of 1.125 percent 6,846 1,093 1,961 The first mortgage bonds issued by Black Hills bonds issued The first mortgage $275 million notes, which were originally scheduled to mature notes, which were originally scheduled in short-term borrowing under our Revolving Credit in short-term borrowing under our Revolving term loan due on June 24, 2013, the Dec. 31, 2013 which included a make-whole provision of approximately provision of approximately which included a make-whole erm Loan for notes originally due on notes originally due (LIBOR plus a mar Deferred Financing Costs $25 million T 143 current on Balance Sheets at Remaining in Other Assets, Non- $ $ $ $ $ $ $ $ $150 million $261 million yoming project financing with a remaining balance of approximately with a remaining balance of approximately yoming project financing W 9.0 percent The payment included accrued interest and a make-whole provision of The payment included accrued interest . (a) senior unsecured note expiring on , 4.25 percent senior unsecured note 1.3125 percent of the Revolving Credit Facility; of senior unsecured 6.5 percent , as well as the interest rate swaps designated to this project financing of rate swaps designated to this project Dec. 9, 2016, as well as the interest $239 million $525 million , for approximately $55 million $225 million notional de-designated interest rate swaps for approximately notional de-designated interest rate swaps $250 million senior unsecured and accrued interest which are included in Interest expense on the accompanying Consolidated which are included in Interest expense and accrued interest which is included in Interest expense on the accompanying Consolidated Statements of Income; Interest expense on the accompanying which is included in originally due on , earnings and other provisions of the mortgage indentures. of the mortgage indentures. and other provisions , earnings $250 million yoming project financing due 2016 W Redeem our occurred on Dec. 19, 2013 $8.5 million Statements of Income; interest rate Black Hills Repay our variable $87 million Pay down approximately purposes. Remainder was used for general corporate $8.5 million Settle the The covenants of the new term loan are substantially the same as the Revolving Credit Facility The covenants of the new term loan are . 19, 2013, we entered into a . 19, 2013, we entered . which are included in Interest expense on the accompanying Consolidated Statements of Income. which are included in Interest expense ransactions T • • • • • This project financing was repaid in 2013 and the deferred financing costs were written-of Senior unsecured notes due 2023 Senior unsecured notes due 2014 Senior unsecured notes due 2020 First mortgage bonds due 2032 First mortgage bonds due 2039 First mortgage bonds due 2037 Black Hills Other ______(a) On June 21, 2013, we entered into a new long-term Corporate On June 21, 2013, we entered into a new from this new debt were used to: from this new debt to repay the proceeds from this new term loan was used amortization expense included in Interest expense on the accompanying Our deferred financing costs and associated as follows (in thousands): Consolidated Statements of Income were Amortization Expense Power and Cheyenne Light are either currently not callable or are subject to make-whole provisions which would eliminate any would eliminate any provisions which to make-whole callable or are subject either currently not Cheyenne Light are Power and the bonds. benefit for us to call economic On Nov and approximately corporate term loan due on Sept. 30, 2013, Facility million Debt indentures the lien of subject to Light is Cheyenne and Hills Power of Black property utility of the tangible all Substantially in amounts be issued Light may Cheyenne Power and Hills of Black bonds First mortgage bonds. mortgage their first securing property limited by cost of borrowing under this new term loan was cost of borrowing under this new term On Oct. 31, 2012, we redeemed on May 15, 2013, for approximately 144 |10K FORM 10K through Interestexpense. the RevolvingCreditFacility Credit FacilityandincludedinInterestexpenseontheaccompanying ConsolidatedStatementsofIncome.Uponenteringinto Deferred financingcostsonthenewfacilityof approximately Eurodollar borrowingsandlettersofcreditwere letters ofcreditisdeterminedbaseduponourratings. other corporatepurposes.BorrowingsareavailableunderabaserateoptionorEurodollaroption. million accordion featureallowingus,withtheconsentofadministrativeagent,toincreasecapacityfacility On Feb.1,2012,weenteredintoanew Revolving CreditFacility W in compliancewithallofthesecovenants. Our RevolvingCreditFacilityanddebtsecuritiescontaincertainrestrictivefinancialcovenants. (6) made byoursubsidiaries. result, certainstatutorylimitationsorregulatoryfinancingagreementscouldaf distributions madebyoursubsidiaries. Due toourholdingcompanystructure,substantiallyallofoperatingcashflowsareprovidedbydividendspaidor default. Our creditfacilityandotherdebtobligationscontainrestrictionsonthepaymentofcashdividendsuponadefaultorevent Dividend Restrictions current creditratings,thefeeis The facilitycontainsacommitmentfeethatischar Corporate TermLoandueJune2013 Revolving CreditFacility Revolving CreditFacility Total e hadthefollowingshort-termdebtoutstandingatConsolidatedBalanceSheetsdate(inthousands): • . As of The RevolvingCreditFacilitycanbeusedfortheissuanceofletterscredit,tofundworkingcapitalneedsand NOTES P restricted netassetsatourUtilitiesGroupwereapproximately the FederalPower Our utilitiesaregenerallylimitedtotheamountofdividendsallowedbepaidourutilityholdingcompanyunder Dec. 31,2013 $22 million A Y ABLE The deferredfinancingcostsonthenewfacilityarebeing amortized asfollows(inthousands): The followingrestrictionsondistributionsfromoursubsidiariesexistedat andapproximately Act andsettlementagreementswithstateregulatoryjurisdictions. , wewereincompliancewiththesecovenants. , $1.5million 0.25 percent The cashtopaydividendsourshareholdersisderivedfromtheseflows. $500 million ofdeferredfinancingcostsrelatingtothepreviouscredit facility werewrittenof . As of $36 million $2.8 million 0.375 percent ged ontheunusedamountofRevolvingCreditFacility Dec. 31,2013 RevolvingCreditFacilityexpiring , respectively arebeingamortizedovertheestimatedusefullifeofRevolving At currentcreditratings,themar 144 , 1.375percentand and2012,wehadoutstandinglettersofcredittotaling $ Balance Sheetsasof Costs Remainingon Deferred Financing . $88 million Dec. 31,2013 fect thelevelsofdistributionsallowedtobe . 1,316 Feb. 1,2017. $ $ Dec. 31,2013 $ Amortization Expensefortheyears gins forbaserateborrowings, As ofDec.31,2013,the 2013 , respectively Balance Outstandingat As of 752 The costofborrowingsor 82,500 82,500 Dec. 31,2013: ended Dec.31, The facilitycontainsan Dec. 31,2013 $ — 2012 $ $ 2,187 , atDec.31,2013. . Basedupon Dec. 31,2012 $ $750 , wewere 277,000 150,000 127,000 2011 As a 1,891 f FORM 10K 10K | 145 274 259 65% 6,922 6,981 51,851 20,627 24,028 20,286 23,022 50,548 , and increased Dec. 31, 2012 Dec. 31, 2013 $ $ $ $ ) aluation — — — — V
580 156 736 o manage and (227 T 1,089 1,316 (a) (a) Less than Covenant Requirement Covenant Estimates Estimates Revisions to Prior Revisions to Prior $ $ $ $ 55% , it is not possible to estimate a time 15 11 291 921 168 2,685 1,052 1,450 1,345 2,568 Accretion Accretion Accordingly $ $ $ $ At Dec. 31, 2013 At Dec. 31, ) ) ) ) ) ) — — — — (22 (714 (2,617 (1,903 (1,059 (1,081 Settled Settled 145 Liabilities Liabilities $ $ $ $ 1. 3 — — — 143 146 158 gy sectors expose us to a number of risks in the normal operations of our 1,627 3,626 5,411 Incurred Incurred e periodically review and update estimated costs related to these asset retirement and update estimated costs related to e periodically review Liabilities Liabilities TIONS erm Loan require compliance with the following financial covenant at the end of financial covenant with the following require compliance erm Loan $ $ $ $ W T ARO which are included on the accompanying Consolidated Balance Sheets in ARO which are included on the accompanying 259 270 , we are exposed to varying degrees of market risk and credit risk. 3,064 6,981 20,286 23,022 17,158 22,422 50,548 42,914 ACTIVITIES
OBLIGA AROs related to certain assets within our electric and gas utility transmission and distribution AROs related to certain assets within our electric and gas utility transmission Dec. 31, 2011 Dec. 31, 2012 $ $ $ $ RETIREMENT , materials and equipment. The actual cost may vary from estimates because of regulatory requirements, changes in technology vary from estimates because of regulatory The actual cost may These retirement obligations are pursuant to an easement or franchise agreement and are only required if we These retirement obligations are pursuant to an easement or franchise agreement RISK MANAGEMENT ASSET The Revisions to Prior Estimates reflects the change in the estimated liability for final reclamation adjusted for inflation, discount rate The Revisions to Prior Estimates reflects the change in the estimated liability for final and market risk premium. Total Total e also have legally required e have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in the Oil and and abandonment of natural gas retirement obligations related to plugging e have identified legal Recourse leverage ratio Recourse Gas Utilities Coal Mining Oil and Gas Gas Utilities Coal Mining Oil and Gas Electric Utilities Electric Utilities mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. mitigate these identified risks, we have adopted the Black Hills Corporation Risk W systems. ______(a) discontinue our utility service under such easement or franchise agreement. (8) period when these obligations could be settled and therefore, a value for the cost of these obligations cannot be measured at this period when these obligations could be settled and therefore, a value for the cost time. Our activities in the regulated and non-regulated ener businesses. Depending on the activity methodologies for our derivatives are detailed within Note Our Revolving Credit Facility and our new Credit Facility Our Revolving Debt Covenants Debt each quarter: (7) W asbestos, transformers Mining segment and removal of fuel tanks, of coal mining sites at the Coal Gas segment, reclamation Utilities segment and and wind turbines at the regulated Electric biphenyls, an evaporation pond containing polychlorinated utilities segments. asbestos at our regulated obligations. costs of labor of The following tables present the details (in thousands): Other deferred credits and other liabilities 146 |10K FORM 10K reported inRevenueontheaccompanyingConsolidatedStatements ofIncome(Loss). hedge accountingisreportedin Consolidated BalanceSheets. The derivativesweremarkedtofairvalueandrecordedasDerivativeassetsorliabilitiesontheaccompanying at leastquarterly derivatives andhedging,initiallymetprospectiveef instruments. and relatedoptionstohedgeportionsofourcrudeoilnaturalgasproduction. T open positions,resultincommoditypriceriskandvariabilitytoourcashflows. W Oil andGasExplorationProduction (Loss) aredetailedbelowandwithinNote Consolidated BalanceSheets,StatementsofIncomeandComprehensive companies, cooperativeutilitiesandfederalagencies.Ourderivativehedgingactivitiesincludedintheaccompanying company As ofDec.31,2013,ourcreditexposureincludeda estimated creditlossesbaseduponhistoricalexperienceandanyspecificcustomercollectionissuethatisidentified. customer W prepayments, lettersofcredit,andothersecurityagreements. netting agreements,andmitigatingcreditexposurewithlesscreditworthycounterpartiesthroughparentalguarantees, credit qualityentities,settingtenorandlimitscommensuratewithcounterpartyfinancialstrength,obtainingmaster For productionandgenerationactivities,weattempttomitigateourcreditexposurebyconductingbusinessprimarilywithhigh Credit riskistheoffinanciallossresultingfromnon-performancecontractualobligationsbyacounterparty Credit Risk following marketrisks,including,butnotlimitedto: Market riskisthepotentiallossthatmayoccurasaresultofanadversechangeinmarketpriceorrate. Market Risk o mitigatecommoditypriceriskandpreservecashflows,weprimarilyuseover e producenaturalgasandcrudeoilthroughourexplorationproductionactivities. e performongoingcreditevaluationsofourcustomersandadjustlimitsbaseduponpaymenthistorythe • • Interest rateriskassociatedwithourvariabledebtandothershort-termlong-terminstruments and fuelprocurementforcertainofourgas-firedgenerationassets; Commodity priceriskassociatedwithournaturallongpositioncrudeoilandgasreservesproduction . ’ s currentcreditworthiness,asdeterminedbyreviewoftheircreditinformation. The remainderofourcreditexposurewasconcentratedprimarilyamongretailutilitycustomers,investmentgrade These transactionsweredesignatedatinceptionascashflowhedges,documentedunderaccountingstandardsfor . The ef AOCI intheaccompanyingConsolidatedBalanceSheetsand theinef fective portionofthegainorlossonthesederivativesforwhich wehaveelectedcashflow 9. $0.5 million
fectiveness testing.Ef 146 exposuretoanon-investmentgradeener fectiveness ofourhedgingpositionisevaluated
-the-counter swaps,exchangetradedfutures W e electhedgeaccountingonthese Our naturallongpositions,orunhedged W e maintainaprovisionfor fective portion,ifany W e areexposedtothe gy marketing . . , is FORM 10K 10K | 147 2 83 72 — 43 — — — 170 507 0.75 9,596 1,831 8,215,500 fsetting as (months) Natural gas and options futures, swaps $ $ $ $ Maximum Term Dec. 31, 2012 1 — $ $ $ $ $ 297 847 1,405 Dec. 31, 2012 — — — Dec. 31, 2012 662 528,000 7,567 2,430,000 15,350,000 12,020,000 Crude oil and options Notional futures, swaps (MMBtus) $ $ $ $ — — — — 8 Dec. 31, 2013 0.08 84 60 AOCI during 2014. Estimated and actual $ $ $ $ $ 7,082,500 These transactions are considered derivatives, These transactions are considered derivatives,
Natural gas and options futures, swaps (months) $ $ $ $ Maximum Term 55 — — — 0.25 , the hedging activity is recognized in the Consolidated , the hedging activity is recognized in the Dec. 31, 2013 412,500 Dec. 31, 2013 147 Crude oil and options 3,890,000 17,930,000 14,785,000 futures, swaps $ $ $ $ Notional Accordingly (MMBtus)
loss would be reclassified from Assets and liabilities are classified as current/non-current based on the timing of the classified as current/non-current based on Assets and liabilities are $1.0 million underlying exposure to these fluctuations. (b) Unrealized and realized gains and losses, as well as option premiums and commissions on these . Unrealized and realized gains and losses, (a) Crude in Bbls, gas in MMBtu. Crude in Bbls, gas in derivative instrument. Refers to the term of the hedged transaction and the corresponding settlement of the derivative instrument. the corresponding settlement of the derivative hedged transaction and e had the following derivative balances related to the hedges in our Utilities reflected in our Consolidated Balance Sheets as e had the following derivative balances related to the hedges in our Utilities reflected Derivative assets, current Derivative assets, non-current Derivative liabilities, current Derivative liabilities, non-current Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities Notional Maximum terms in years Maximum terms in Derivative assets, current Derivative assets, non-current current Derivative liabilities, non-current Derivative liabilities, Natural gas options purchased Natural gas basis swaps purchased Natural gas futures purchased realized gains or losses will change during future periods as market prices fluctuate. realized gains or losses will change during The operations of our utilities, including power purchase arrangements where our utilities must provide the generation fuel power purchase arrangements where our utilities must provide the generation The operations of our utilities, including by state customers to volatility in natural gas prices; therefore, as allowed or required, (tolling agreements), expose our utility and commission-approved hedging programs utilizing natural gas futures, options utility commissions, we have entered into basis swaps to reduce our customers’ Utilities Based on Dec. 31, 2013 market prices, a (a) (b) The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Gas Utilities were of the natural gas derivative commodity instruments held by our Gas Utilities The contract or notional amounts and terms as follows, as of: ______are Statements of Comprehensive Income (Loss) when the related costs Statements of Income (Loss) or the Consolidated recovered through our rates. W of (in thousands): The contract or notional amounts, terms of our commodity derivatives, and the derivative balances for our Oil and Gas segment Gas segment our Oil and for balances the derivative and derivatives, commodity terms of our amounts, notional or The contract as of: thousands) in follows (dollars were as Sheets Balance Consolidated on the reflected and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as for derivatives and hedging, mark-to-market adjustments are recorded as and in accordance with accounting standards on the accompanying Consolidated Balance Sheets, net of balance sheet of Derivative assets or Derivative liabilities permitted by GAAP in assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets transactions are recorded as Regulatory guidelines. accordance with the state utility commission 148 |10K FORM 10K accordance withaccountingstandardsforof netting agreementsthatallowustosettlepositiveandnegativepositions,ofassetliabilitypositionspermitte d in included incashcollateralandcounterpartynettingthefollowingtablesrepresentimpactoflegallyenforceable master There havebeennosignificanttransfersbetweenLevel1and2derivativebalancesduring Recurring Fair (9) and realizedgainsorlosseswillchangeduringfutureperiodsasmarketinterestrateschange. $3.5 million Based onDec.31,2013marketinterestratesandbalancesrelatedtoourdesignatedrateswaps,alossofapproximately (c) (b) (a) ______swaps balancesreflectedontheConsolidatedBalanceSheetswereasfollows(dollarsinthousands)of: with ourfloatingratedebtobligations. W Financing Derivative liabilities,non-current Derivative liabilities,current Maximum termsinyears Weighted averagefixedinterestrate Notional e enteredintofloating-to-fixedinterestrateswapagreementstoreduceourexposurefluctuationsassociated settled uponrepaymentoftheBlackHills 2013. have requiredcashsettlementbasedontheswapvalueatterminationdate. Maximum termsinyearsreflecttheamendedearlyterminationdates.Ifdateswerenotextended,swaps would LIBOR, matchingthefloatingportionofrelatedswaps. million At Dec.31,2012,$75million matching thefloatingportionofrelatedswaps. These swapsaredesignatedtoborrowingsonourRevolvingCreditFacility F AIR Activities weredesignatedtoborrowingsonourprojectfinancingdebtatBlackHills wouldberealized,reportedinpre-taxearningsandreclassifiedfrom V V alue Measurements ALUE MEASUREMENTS oftheseinterestrateswapsweredesignatedtoborrowingsonourRevolvingCreditFacilityand The contractornotionalamounts,termsofourinterestrateswapsandthe W fsetting aswellcashcollateralpostedwiththesamecounterparties. yoming projectfinancing.SeeNote
The portionoftheswapsthatweredesignatedtoBlackHills 148 . These swapsarepricedusingthree-monthLIBOR, These swapsweresettledduringthefourthquarterof $ $ $ Dec. 31,2013 5. Interest Rate W Swaps yoming. AOCI duringthenext12months.Estimated 75,000 5,614 3,474 4.97% (a) 3.0 These swapsarepricedusingthree-month $ $ $ Interest Rate Swaps 2013 or2012. 150,000 16,941 7,039 Dec. 31,2012 5.04% (b) 4.0 $ $ $ Amounts De-designated Interest Rate W Swaps yoming were 250,000 88,148 $75 (c) 5.67% — 1.0 FORM 10K 10K | 149 — 55 — — — — — — — 662 717 9,088 9,088 Total $ $ $ $ — — — — — (75) (815) (531) (2,368) (9,100) (1,229) (3,258) (10,860) Netting that were accounted for at for were accounted that Cash Collateral and Counterparty $ $ $ $ — — — — — — — — — — — — — As of Dec. 31, 2013 As of Dec. Level 3 $ $ $ $ The following tables set forth, by level within the fair the fair level within forth, by tables set The following — — — — 130 815 531 10. 3,030 9,100 1,229 9,088 3,975 19,948 fsetting as permitted by GAAP as permitted fsetting Level 2 $ $ $ $ 149 — — — — — — — — — — — — — Level 1 $ $ $ $ , our gross assets and gross liabilities and related of and related liabilities and gross gross assets , our Options -- Oil Options -- Oil Basis Swaps -- Oil Options -- Gas Basis Swaps -- Gas Basis Swaps -- Oil Options -- Gas Basis Swaps -- Gas Commodity derivatives - Oil and Gas: Commodity derivatives Commodity derivatives - Utilities Commodity derivatives Total Commodity derivatives - Oil and Gas: Commodity derivatives - Utilities Interest rate swaps Total discussion of fair value of financial instruments is included in Note in is included instruments of financial value of fair discussion Assets: Liabilities: A value hierarchy value (in thousands): instruments derivative basis for recurring on a fair value 150 |10K FORM 10K (a) ______The followingtablepresentsthequantitativeinformationaboutLevel3fairvaluemeasurements(dollarsinthousands): Commodity derivatives-Utilities Assets: Assets: Liabilities: Total Interest rateswaps Commodity derivatives-OilandGas: Commodity derivatives-Utilities Total Commodity derivatives-Utilities Commodity derivatives-OilandGas: Options --Oil Basis Swaps--Gas Options --Gas Basis Swaps--Oil Basis Swaps--Gas Options --Gas Options --Oil Basis Swaps--Oil are available. contracts willbeclassifiedasLevel2oncesettlementiswithin60 monthsofmaturityandquotedmarketpricesfromaexchange asset/liability gas prices.Significantchangestotheseinputsalongwiththecontracttermwouldimpactderivativeasset/liabilityandregulatory quotes fromanindependentthirdpartymarketparticipantandtheOTCcontractbroker The significantunobservableinputsusedinthefairvaluemeasurementoflong-termOTCcontractsarebasedonaverageprice , butwillnotimpacttheresultsofoperationsuntilcontractissettledunderoriginaltermscontract. (a) $ Dec. 31,2012 Fair Valueat $ $ $ $ Level 1 43 quotes Independent price — — — — — — — — — — — — — 150 Technique Valuation $ $ $ $ Level 2 129,424 118,088 8,576 3,703 2,000 1,325 1,127 1,131 378 502 — — — $ $ $ $ Level 3 prices -BasisDifferential Long-term naturalgas As ofDec.31,2012 . The unobservableinputsarelong-termnatural — — — 43 — — — — 43 — — — — Unobservable Input $ $ $ $ and Counterparty Cash Collateral Netting (15,942) (5,960) (8,576) (620) (450) (336) — — — — — — — $ Range (Weighted) $ $ $ $ Average Total The 113,482 112,128 (0.13 3,746 2,000 1,325 507 378 795 — 43 — — 52 ) FORM 10K 10K | 151 43 — — — — — — (54) (95) (54) 192 821 1,993 7,038 4,957 5,153 16,941 26,793 94,108 104,218 Fair Value of Liability Derivatives $ $ $ $ fsetting and gin accounts at 2012 Commodity — — — — — — — 510 362 406 2,874 3,384 1,180 1,948 $ $ As of Dec. 31, 2012 Dec. 31, As of $ Derivatives -- Utilities Derivatives of Asset — — 43 — — Fair Value (43) Derivatives $ $ $ $ — — — — — — — 219 1,541 3,474 5,614 6,732 6,732 10,848 Commodity Fair Value of Liability Derivatives $ $ $ $ As of Dec. 31, 2013 As of $ $ Derivatives -- Utilities Derivatives $ 2013 — — — — — — — — — 698 946 662 662 248 of Asset Fair Value Derivatives $ $ $ $ 151 8. , the amounts do not include net cash collateral on deposit in mar , the amounts do not include net cash collateral Balance Sheet Location Derivative assets - current Derivative assets - current Derivative assets - non-current Derivative liabilities - current Derivative liabilities - non-current Derivative liabilities - current Derivative liabilities - non-current Derivative assets - non-current Derivative liabilities - current Derivative liabilities - non-current Derivative liabilities - current Derivative liabilities - non-current , positively impacting the availability of observable pricing inputs. , positively impacting the (a) es by Balance Sheet Classification es by Balance Sheet , the amounts below will not agree with the amounts presented on our Consolidated Balance Sheets, nor will they , the amounts below will not agree with Therefore, the balances are not indicative of either our actual credit exposure or net economic exposure. Therefore, the balances are not indicative alue Measur on date and the delivery observable such as the time between the valuati occur when the significant inputs become more ransfers out of Level 3 would ransfers out of Level 3 T shorter date of a transaction becomes Total gain (loss) included in AOCI/ Regulatory Asset (loss) included in AOCI/ Total gain Purchases T Commodity derivatives Commodity derivatives Commodity derivatives Commodity derivatives Commodity derivatives Interest rate swaps Interest rate swaps Commodity derivatives Commodity derivatives Commodity derivatives Interest rate swaps Interest rate swaps Changes in unrealized gains (losses) relating to instruments still held as of period-end gains (losses) relating to instruments still Changes in unrealized Balances at end of period Total derivatives designated as hedges Derivatives not designated as hedges: Total derivatives not designated as hedges Derivatives designated as hedges: Assets: Balances as of beginning of period Balances as As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross fair values within the following standards for derivatives and hedges, As required by accounting liability positions permitted in accordance with accounting standards for of basis reflecting the netting of asset and Fair V ______(a) under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to and the impact of legally enforceable master netting agreements that allow under terms of our master netting agreements settle positive and negative positions. However The following tables present the changes in Level 3 recurring fair value (in thousands): value (in fair Level 3 recurring in the changes tables present The following , to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative Dec. 31, 2013 and 2012, to collateralize certain financial instruments, liabilities. presented in Note correspond to the fair value measurements (in and balance sheet classification of our derivative instruments as of Dec. 31, The following tables present the fair value thousands): Additionally 152 |10K FORM 10K thousands): Of exposure orneteconomicexposure. Derivative assetsand/orliabilities. mar well ascashcollateralpostedwiththesamecounterparties. well astheimpactoflegallyenforceablemasternettingagreementsthatallowustosettlepositiveandnegativepositions tables includethenettingofassetandliabilitypositionspermittedinaccordancewithaccountingstandardsfor amounts tothenetamounts. As requiredbyaccountingstandardsforderivativesandhedges,fairvalueswithinthefollowingtablesreconcilegross accounts receivableandpayablederivativeactivities. It isourpolicytoof Commodity derivative: Not subjecttoamasternettingagreementorsimilararrangement: arrangement Total derivativeassetssubjecttoamasternettingagreementorsimilar Total derivativeassets arrangement Total derivativeassetsnotsubjecttoamasternettingagreementorsimilar Commodity derivative: Subject tomasternettingagreementorsimilararrangement: Derivatives Of Utilities Oil andGas-NaturalBasisSwaps Oil andGas-CrudeOptions Oil andGas-CrudeBasisSwaps Utilities Oil andGas-CrudeOptions Oil andGas-CrudeBasisSwaps Oil andGas-NaturalBasisSwaps fsetting ofderivativeassetsandliabilitiesonourConsolidatedBalanceSheetsat gin accountsat fsetting Dec. 31,2013and fset inourConsolidatedBalanceSheetscontractswhichprovideforlegallyenforceablenetting Derivative Assets Amounts includedinGross Dec. 31,2012,tocollateralizecertainfinancialinstruments,whichareincludedin Therefore, thegrossamountsarenotindicativeofeitherouractualcredit Amounts Of Additionally 152 fset onConsolidatedBalanceSheetsinthefollowing , theamountsreflectcashcollateralondepositin $ $ Amounts of Derivative Assets Gross 3,920 3,975 3,030 815 — — — 55 55 — 75 $ $ Gross Amounts Balance Sheets Consolidated Offset on Dec. 31,2013wasasfollows(in (3,258) (2,368) (3,258) (815) (75) — — — — — — $ $ Consolidated Balance Derivative Assetson Net AmountofTotal fsetting as Sheets 662 662 717 — — — 55 55 — — — FORM 10K 10K | 153 — 76 93 — — 43 — — — — — — — — 172 285 384 1,249 1,828 3,362 3,746 9,088 9,088 9,088 Sheets Balance Sheets Balance on Consolidated Net Amount of Total Derivative Assets on Net Amount of Total Net Amount Derivative Liabilities Derivative Consolidated Balance $ $ $ $ — — — — — — — — — — — — — — — — (531) (1,229) (1,586) (1,586) (9,100) (1,586) (10,860) (10,860) Dec. 31, 2012 were as follows Offset on Offset on Offset Consolidated Consolidated Balance Sheets Balance Sheets Balance Gross Amounts Gross Amounts Gross $ $ $ $ 93 76 — — — — — — — 531 172 285 1,629 1,229 9,100 1,970 1,828 3,362 5,332 1,249 9,088 9,088 10,860 19,948 Gross Gross Assets Liabilities Derivative Derivative Amounts of Amounts of Amounts $ $ $ $ 153 Derivative Assets Derivative Liabilities Derivative fsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of fsetting of derivative assets and derivative Oil and Gas - Natural Gas Basis Swaps Oil and Gas - Natural Oil and Gas - Crude Options Oil and Gas - Natural Gas Basis Swaps Utilities Oil and Gas - Crude Basis Swaps Oil and Gas - Crude Options Oil and Gas Oil and Gas - Crude Basis Swaps Oil and Gas Utilities Oil and Gas - Crude Options Oil and Gas - Natural Gas Basis Swaps Utilities Oil and Gas - Crude Basis Swaps Oil and Gas - Crude Options Oil and Gas - Natural Gas Basis Swaps Utilities Oil and Gas - Crude Basis Swaps Oil and Gas - Crude Basis Subject to master netting agreement or similar arrangement: Subject to master netting agreement or similar Commodity derivative: Total derivative assets subject to a master netting agreement or similar arrangement Total derivative assets not subject to a master netting agreement or similar arrangement Total derivative assets Subject to a master netting agreement or similar arrangement: master netting agreement Subject to a derivative: Commodity Interest Rate Swaps similar subject to a master netting agreement or Total derivative liabilities arrangement Interest Rate Swaps netting agreement or similar Total derivative liabilities not subject to a master arrangement Total derivative liabilities Not subject to a master netting agreement or similar arrangement: Commodity derivative: Not subject to a master netting agreement or similar arrangement: Not subject to a master Commodity derivative: (in thousands): Of 154 |10K FORM 10K of Dec.31,2013were(inthousands): Derivative assetsandderivativeliabilitiescollateralheldbycounterpartyincludedinourConsolidatedBalance Sheets as Total derivativeliabilities Commodity derivative: Not subjecttoamasternettingagreementorsimilararrangement: arrangement Total derivativeliabilitiesnotsubjecttoamasternettingagreementorsimilar Interest RateSwaps arrangement Total derivativeliabilitiessubjecttoamasternettingagreementorsimilar Interest RateSwaps Commodity derivative: Subject toamasternettingagreementorsimilararrangement: Interest RateSwaps Utilities Oil andGas Oil andGas Liabilities: Oil andGas Assets: Utilities Oil andGas Oil andGas-CrudeBasisSwaps Utilities Oil andGas-NaturalBasisSwaps Oil andGas-CrudeOptions Utilities Oil andGas-NaturalBasisSwaps Oil andGas-CrudeOptions Oil andGas-CrudeBasisSwaps Contract Type Contract Type Counterparty F Counterparty A Counterparty B Counterparty A Counterparty A Counterparty A Counterparty B Derivative Liabilities $ $ $ $ Derivative Liabilities Net AmountofTotal Net AmountofTotal Derivative Assets 154 9,088 9,088 717 662 — — — — 55 $ $ $ $ $ $ Amounts of Derivative Liabilities Gross AmountsNotOffseton Gross AmountsNotOffseton Consolidated BalanceSheets Consolidated BalanceSheets Gross Cash CollateralReceived 129,424 119,442 118,088 Cash CollateralPaid 9,982 8,576 507 795 620 337 449 — 52 — $ $ Gross Amounts Balance Sheets Consolidated Offset on (15,942) (5,021) (3,390) (1,631) (5,960) (9,982) (5,960) (8,576) (620) (337) (449) — — — — — — — — — — — $ $ $ $ $ $ Derivative Liabilities Net AmountofTotal Net Amountwith Net Amountwith on Consolidated Balance Sheets Counterparty Counterparty 113,482 113,482 112,128 (3,390) (1,631) 9,088 4,067 507 795 662 717 — — — 52 — — — — — — 55 FORM 10K 10K | 155 43 — — — 341 3,746 3,362 1,354 4,588 (1,787) (4,354) 29,245 12,721 26,520 16,809 22,245 107,341 Portion) Derivative Income on Amount of (Ineffective Gain/(Loss) Recognized in Counterparty Counterparty $ $ Net Amount with Net Amount with Net Amount $ $ $ $ — — — — — — — — — — — (1,787) (4,354) (6,141) Portion) Derivative (Ineffective in Income on Location of Gain/ (Loss) Recognized ) (927 6,062 6,989 Cash Collateral Paid Cash Collateral Received Cash Collateral Portion) Consolidated Balance Sheets Consolidated Sheets Consolidated Balance Gross Amounts Not Offset on Gross Amounts on Gross Amounts Not Offset (Effective Dec. 31, 2013 Amount of from AOCI $ $ $ $ Gain/(Loss) into Income Reclassified $ $ 43 — — 341 3,362 3,746 1,354 4,588 29,245 12,721 26,520 16,809 22,245 113,482 The following tables present the impact that derivatives had on The following tables present the impact 155 8. Portion) Derivative Assets Derivative from AOCI into Net Amount of Total Net Amount Net Amount of Total Location of Gain/ Income (Effective Derivative Liabilities (Loss) Reclassified Revenue Interest expense $ $ $ $ ) (956 6,979 7,935 Portion) in AOCI (Effective Derivative Amount of Recognized Gain/(Loss) $ $ Counterparty B Counterparty A Counterparty A Counterparty A Counterparty B Counterparty A Counterparty D Counterparty E Counterparty F Counterparty G Counterparty H Counterparty I Contract Type Contract Type description of our derivative activities is included in Note description of our derivative activities Oil and Gas Utilities Derivatives in Cash Flow Hedging Relationships Liabilities: Oil and Gas Commodity derivatives Total Assets: Oil and Gas Oil and Gas Utilities Interest rate swaps Interest Rate Swap Interest Rate Swap Interest Rate Swap Interest Rate Swap Interest Rate Swap Interest Rate Swap The impact of cash flow hedges on our Consolidated Statements of Income (Loss) for years ended were as follows (in Consolidated Statements of Income (Loss) for years ended were as follows (in The impact of cash flow hedges on our thousands): our Consolidated Statements of Income (Loss). our Consolidated Statements of Income Cash Flow Hedges A Derivative assets and derivative liabilities and collateral held by counterparty included in our Consolidated Balance Sheets as Sheets Balance Consolidated in our included counterparty held by collateral and liabilities and derivative assets Derivative (in thousands): were 31, 2012 of Dec. 156 |10K FORM 10K the yearsendedDec.31wereasfollows(inthousands): The impactofderivativeinstrumentsnotdesignatedashedgeonourConsolidatedStatementsIncome (Loss)for Derivatives NotDesignatedasHedgeInstruments Interest rateswaps Interest rateswaps Interest rateswaps-realized unrealized Interest rateswaps- Total Commodity derivatives Total Commodity derivatives Derivatives NotDesignated as HedgingInstruments Derivatives inCashFlow Derivatives inCashFlow Hedging Relationships Hedging Relationships Interest expense Unrealized gain(loss)on Location ofGain/(Loss) Recognized inIncome interest rateswap,net $ $ $ $ Recognized in Recognized in Gain/(Loss) Gain/(Loss) on Derivatives Amount of Amount of Derivative Derivative (Effective (Effective Portion) Portion) AOCI AOCI (12,280 (4,794 (4,539 (2,155 7,741 2,639 ) ) ) ) Interest expense Interest expense Revenue Revenue (Effective Portion) (Effective Portion) AOCI intoIncome AOCI intoIncome Location ofGain/ Location ofGain/ Reclassified from Reclassified from (Loss) (Loss) $ $ Amount ofGain/ 156 Recognized in Derivatives (Loss) on Income 2013 (12,902 $ $ $ $ 30,169 17,267 Dec. 31,2012 Dec. 31,2011 Reclassified Reclassified into Income into Income Gain/(Loss) Gain/(Loss) from AOCI from AOCI Amount of Amount of (Effective (Effective Portion) Portion) ) $ $ (7,664 (7,607 (2,177 5,487 8,784 1,177 Amount ofGain/ Recognized in Derivatives (Loss) on ) ) ) Income 2012 (Loss) Recognized (Loss) Recognized Location ofGain/ Location ofGain/ in Incomeon in Incomeon (Ineffective (Ineffective Derivative Derivative Portion) Portion) (12,959 (11,077 1,882 ) ) $ $ Amount ofGain/ Recognized in Derivatives $ $ $ $ (Loss) on Recognized in Recognized in Income Gain/(Loss) Gain/(Loss) (Ineffective (Ineffective Amount of Amount of 2011 Income on Income on Derivative Derivative Portion) Portion) (42,010 (13,373 (55,383 — — — — — — ) ) ) FORM 10K 10K | 157 5,643 7,916 15,462 277,000 1,231,559 2011
Fair Value $ $ $ $ $ 2012 , were as follows at as follows 9, were , that the market risk and is expected to be 8,271 7,916 As of Dec. 31, 2013, total 15,462 277,000 2012 1,042,850 Amount Carrying $ $9.9 million $ $ $ $ 2 e believe however W
12,595 7,841 82,500 2013 1,491,422 or variable interest rates that approximate prevailing or variable interest rates Fair Value $ . $ $ $ $ 2 2013 7,841 Dec. 31, 2013. 82,500 157 1,396,948
5. Amount Carrying . . Stock-based compensation expense included in Operations and $ $ $ $ 1.7 years (b) INSTRUMENTS (a) FINANCIAL (a) e had 768,953 shares available to grant at W ALUE OF ALUE V (a) OCK AIR As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with As part of our cash management process, ST F erm Debt Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and directly or indirectly for similar liabilities based on observable inputs available either Long-term debt is valued in Level 2 in the fair value hierarchy therefore is classified Carrying value approximates fair value due to either short-term length of maturity fair value due to either short-term length Carrying value approximates market rates and therefore is classified in Level 1 in the fair value hierarchy is classified in Level 1 in the fair value market rates and therefore 1) Stock-based compensation expense Restricted cash and equivalents Restricted cash and Notes payable current maturities Long-term debt, including Cash and cash equivalents (b) in accordance with the provisions of accounting Compensation expense is determined using the grant date fair value estimated the individual awards. standards for stock compensation and is recognized over the vesting periods of unrecognized compensation expense related to non-vested stock awards was approximately Our 2005 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and Our 2005 Omnibus Incentive Plan allows for the granting of stock, restricted performance shares. Equity Compensation Plans Included in cash and cash equivalents is cash, overnight repurchase agreement accounts, money market funds and term cash, overnight repurchase agreement accounts, money market funds and term Included in cash and cash equivalents is deposits. (1 follows for the years ended Dec. 31 (in maintenance on the accompanying Consolidated Statements of Income was as thousands): Cash and Cash Equivalents and are not insured by the U.S. Government, the FDIC or any other our bank. Repurchase agreements are not deposits risk including possible loss of principal. government agency and involve investment (a) debt, see Note For additional information on our long-term The estimated fair values of our financial instruments, excluding derivatives which are presented in Note in Note are presented which derivatives excluding instruments, of our financial fair values The estimated thousands): Dec. 31 (in ______Long-T recognized over a weighted-average period of 2013 Notes Payable represents our Revolving Credit Facility while 2012 also includes certain corporate term loans. 2013 Notes Payable represents our Revolving Notes Payable (10) restricted cash and uninsured term deposits. Restricted cash and cash equivalents represent Restricted Cash and Equivalents arising from holding these financial instruments is minimal. arising from holding these financial instruments 158 |10K FORM 10K contingent oncontinuedemployment.Compensationexpense relatedtotheawardsisrecognizedovervestingperiod. The sharescarryarestrictionontheabilitytosell untilthesharesvest. The fairvalueofrestrictedstockawardsequalsthemarket priceofourstockonthedategrant. Restricted Stock over aweighted-averageperiodof As ofDec.31,2013,theunrecognizedcompensationexpenserelatedtonon-vestedstockoptionsisexpectedberecognized (b) (a) ______The tablebelowprovidesdetailsofouroptionplansatDec.31(inthousands): (a) ______A options grantedvestproportionatelyover W Stock Options Balance atbeginningofperiod T Net cashreceivedfromexerciseofoptions Intrinsic valueofoptionsexercised Unrecognized compensationexpense Summary ofStockOptions Exercisable atendofperiod Balance atendofperiod summaryofthestatusstockoptionsat ax benefitrealizedfromexerciseofshares Granted Exercised Expired Forfeited/canceled e havegrantedoptionswithanoptionexercisepriceequaltothefairmarketvalueofstockondaygrant. The taxbenefitrealizedfromtheexerciseofsharesgrantedwasrecordedasanincreaseinequity the option. The intrinsicvaluerepresentstheamountbywhichmarketpriceofstockondateexerciseexceeded year expectedlife. the fairvaluewerea The grantdatefairvalueofthe2013awardswas (a) 1.4 percentriskfreeinterestrate, 1.1 years. (a) 3 yearsandexpire (b) Dec. 31,2013wasasfollows: $7.65 basedonaBlack-Scholesoptionpricingmodel. 29.3 percent (in thousands) Shares 10 yearsafterthegrantdate. 158 expectedpricevolatility 121 (66 10 26 61 — (4 ) ) $ $ $ Exercise Price Weighted- Average $ $ $ $ The sharessubstantiallyvestover 2013 31.23 40.39 30.87 29.09 31.69 33.25 — , 3.8percent 2,046 276 789 130 Weighted-Average Contractual Term . Remaining $ $ $ $ (in years) expecteddividendyieldanda Assumptions usedtoestimate 6.5 7.3 2012 2,839 218 623 218 $ $ $ $ $ $ Intrinsic Value (in thousands) Aggregate 3 years, 2011 The 1,009 1,165 479 534 33 94 7 FORM 10K 10K | 159 36.76 32.23 40.56 30.62 35.50 5,842 3,781 3,211 100 175% 200% 200% The final Maximum . Shares Vested (in thousands) Dec. 31, 2013 Date Fair Value Date Fair Total Fair Value of $ $ $ Weighted-Average Grant Weighted-Average $ $ 0% 0% 0% ) ) (7 40.56 34.99 30.33 Minimum 262 287 120 (138 Possible Payout Range of Target $1.9 million at The cash portion accrued is classified as The cash portion accrued is classified as (in thousands) Weighted-Average Restricted Stock Restricted Grant Date Fair Value $ $ $ 62 64 61 Target Grant of Shares , was as follows: , was 159 1.8 years. 50 percent in common stock. . In the event of a change-in-control, performance awards are paid . In the event of a change-in-control, performance Dec. 31, 2013 Dec. of unrecognized compensation expense related to non-vested restricted stock that is of unrecognized compensation expense 50 percent in cash and . Performance Period Jan. 1, 2011 - Dec. 31, 2013 Jan. 1, 2012 - Dec. 31, 2014 Jan. 1, 2013 - Dec. 31, 2015 ficers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. ficers of the Company and its subsidiaries in cash. If it is determined that a change-in-control is probable, the equity portion of in cash. If it is determined that a change-in-control Grant Date Jan. 1, 2011 Jan. 1, 2012 Jan. 1, 2013 Granted Vested Forfeited summary of the status of the restricted stock at stock the restricted status of of the summary Restricted Stock at end of period Restricted Stock at Restricted Stock balance at beginning of period Stock balance at beginning Restricted 2013 2012 2011 The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years granted and the total fair value of shares grant-date fair value of restricted stock The weighted-average as follows: ended Dec. 31, was percent would be reclassified as a liability 31 were as follows (shares in thousands): Outstanding performance periods at Dec. a liability and the stock portion is classified as equity a liability and the stock portion is classified The performance awards are paid value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based according to the number of shares of common stock that are ultimately granted value of the performance shares will vary performance criteria. upon the actual level of attainment of the Certain of on our total shareholder return over designated performance periods as measured Performance shares are awarded based certain stock price performance must be achieved for a payout to occur against a selected peer group. In addition, Performance Share Plan As of Dec. 31, 2013, there was $5.8 million period of expected to be recognized over a weighted-average A 160 |10K FORM 10K volatility and simulation usingablendedvolatilityof The grantdatefairvaluesfortheperformancesharesgrantedin purchasing thesharesonopenmarket. and/or optionalcashpaymentsat W Shar plans thatisexpectedtoberecognizedoveraweighted-average periodof As ofDec.31,2013,therewas$3.9million a payoutequalto return forthe On Jan.29,2014,theCompensationCommitteeofourBoardDirectorsdeterminedthatCompany’ Performance planpayoutshavebeenasfollows(dollarsandsharesinthousands): The weighted-averagegrant-datefairvalueofperformanceshareawardsgrantedintheyearsendedwasasfollows: security rateinef A Performance Sharesbalanceatendofperiod Performance Sharesbalanceatbeginningofperiod Jan. 1,2008toDec.31,2010 Jan. 1,2009toDec.31,2011 Jan. 1,2010toDec.31,2012 Performance Period Dec. 31,2011 Dec. 31,2012 Dec. 31,2013 summaryofthestatusPerformanceSharePlanatDec.31wasasfollows: Vested Forfeited Granted e haveaDRIP eholder DividendReinvestmentandStockPur Jan. 1,201 50 percent underwhichshareholdersmaypurchaseadditionalshares ofcommonstockthroughdividendreinvestment fect asofthegrantdate. 175 percent impliedvolatilityandtheaveragerisk-freeinterestrateofthree-yearUnitedStates 1 throughDec.31,2013performanceperiodwasatthe oftar 100 percent get shares,valuedat 20 percent,21 W ofunrecognizedcompensationexpenserelatedtooutstanding performanceshare e arecurrentlyissuingnewshares. oftherecentaveragemarketprice. chase Plan (in thousands) $6.0 million Shares and30percent 160 Equity Portion 2013, 2012and (33 93 31 96 . (1 The payoutwasfullyaccruedat ) ) Payment Year of $ $ Date FairValue 2011 2012 2013 Average Grant 1.6 years. Weighted- , respectively 201 94 W 24.26 33.85 31.34 35.85 27.49 th e havetheoptionofissuingnewsharesor Stock Issued 1 weredeterminedbyMonteCarlo percentileofitspeergroupandconfirmed , comprisedof50percent (in thousands) Shares — — 63 $ $ $ Weighted AverageGrant $ $ $ Liability Portion Cash Paid (33 Dec. 31,2013. Date FairValue 93 31 96 (1 s totalshareholder ) ) 2,267 $ Weighted-Average — — Dec. 31,2013 Fair Valueat T reasury $ $ $ historical Intrinsic Value Total 25.92 32.26 35.85 95.79 4,533 — — FORM 10K 10K | 161 101 353 6,125 33.58 1 we 2012 2011 fering of . 1, 201 $ -allotment option $ $95.67 per barrel, 67 286 46.78 These capitalized costs, 6,839 2013 Any costs in excess of the 2012 under an Equity Forward under an Equity Forward $ $27 million non-cash impairment Agreement. On Nov $ $120 million 7,169 gan in connection with a public of gan in connection with 2013 , the underwriters exercised the over , the underwriters exercised . Mor fice facilities. Rental expense incurred under these $ shares of preferred stock of which we had no shares of shares of preferred stock of which we 161 25 million Agreement with J.P ASSETS ge. per Mcf at the wellhead; for crude oil, the average NYMEX price was $2.66 per Mcf at the wellhead; for crude oil, LONG-LIVED OF f as a non-cash char TING LEASES AIRMENT $85.36 per barrel at the wellhead. OPERA IMP , we entered into an Equity Forward . 10, 2010, we entered into an ed Stock eferr e have entered into lease agreements for vehicles, equipment and of summary of the Dividend Reinvestment and Stock Purchase Plan for the years ended and at Dec. 31 is as follows (shares in (shares as follows Dec. 31 is and at years ended for the Plan Stock Purchase and Reinvestment Dividend of the summary Rent expense Shares Issued Average Price Weighted Unissued Shares Available operating leases, including month to month leases, for the years ended Dec. 31 was as follows (in thousands): operating leases, including month to month leases, for the years ended Dec. 31 W less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the deferred income taxes, are subject to a ceiling test that limits the pooled costs less accumulated amortization and related a net revenue attributable to proved natural gas and crude oil reserves using aggregate of the discounted value of future lower of cost or market value of unevaluated properties. discount rate defined by the SEC plus the ceiling are written of prices in the second quarter of 2012, we recorded a As a result of continued low commodity the average and Gas segment. In determining the ceiling value of our assets, we utilized of oil and gas assets included in the Oil price each month from the previous 12 months. For natural gas, the average NYMEX of the quoted prices from the first day of was $3.15 per Mcf, adjusted to adjusted to (13) Under the full cost method of accounting used by our Oil and Gas segment to account for exploration, development, and used by our Oil and Gas segment to account for exploration, development, Under the full cost method of accounting reserves, all costs attributable to these activities are capitalized. acquisition of crude oil and natural gas Our articles of incorporation authorize the issuance of Our articles of incorporation authorize Pr (12) shares of Black Hills Corporation common stock. Subsequently 4,000,000 shares of Black Hills Equity the same terms as the original Forward additional shares under to purchase 413,519 stock in return for proceeds of approximately issued 4,413,519 shares of common Agreement. preferred stock outstanding. On Nov Equity Issuance thousands): A 162 |10K FORM 10K Income taxexpense(benefit)fromcontinuingoperationsfortheyearsendedDec.31was(inthousands): (14) The followingisascheduleoffutureminimumpaymentsrequiredundertheoperatingleaseagreements(inthousands): Total incometaxexpense(benefit) Deferred: Current: Tax creditamortizationexpense(benefit) Deferred stateincometaxexpense(benefit) Deferred federalincometaxexpense(benefit) Current stateincometaxexpense(benefit) Current federalincometaxexpense(benefit) INCOME T AXES Thereafter 2018 2017 2016 2015 2014 162 $ $ $ $ $ $ $ $ 5,452 1,697 1,747 1,938 2,583 2,782 2013 61,608 63,784 56,963 (2,176 (2,003 7,033 (212 (173 ) ) ) ) $ $ 2012 48,400 39,716 39,876 8,684 3,712 4,972 (228 68 ) $ $ 2011 (15,376 (14,539 18,224 33,600 30,876 2,970 (246 (837 ) ) ) ) FORM 10K 10K | 163 (6,192) 57,471 23,767 20,038 35,947 55,971 15,546 36,502 (23,537) (48,411) (17,723) (19,986) (13,961) 147,153 386,203 (571,262) (694,880) (308,677) 2012 $ $ 9,733 1,594 (1,806) 33,172 28,724 55,124 14,948 32,803 (24,581) (69,799) (15,593) (30,293) (15,104) 166,095 340,387 (598,415) (753,785) (413,398) 2013 $ $ , for the years ended Dec. 31 were as follows (in as follows 31 were Dec. years ended , for the 163 ferences, which gave rise to the net deferred tax liability deferred to the net gave rise which ferences, Total deferred tax assets Total deferred tax liabilities Net deferred tax liability Regulatory liabilities Regulatory Employee benefits Employee Items of other comprehensive income (loss) comprehensive income Items of other Derivative fair value adjustments Federal net operating loss Federal net operating Asset impairment State tax credits Other deferred tax assets Less: Valuation allowance Accelerated depreciation, amortization and other plant-related differences Accelerated depreciation, amortization and Regulatory assets Mining development and oil exploration Deferred costs State deferred tax liability Other deferred tax liabilities Deferred tax assets: Deferred tax Deferred tax liabilities: The temporary dif The temporary thousands): 164 |10K FORM 10K As ofDec.31,2013,wehada$0.5million of future taxfilings.IfthevaluationallowanceisadjustedduetohigherorlowerthananticipatedutilizationofNOLs, the carryforward periodhasexpiredresultinginanof million ability toutilizesuchNOLsresultedinadecreaseofthevaluationallowanceapproximately At Dec.31,2013,wehadfederalandstateNOL (a) ______The ef Other taxdifferences Flow-through adjustments Accounting foruncertaintaxpositionsadjustment Tax credits Equity AFUDC Percentage depletioninexcessofcost Amortization ofexcessdeferredandinvestmenttaxcredits State incometax(netoffederaleffect) Federal statutoryrate fsetting amountwillaf impact ontheef continue torecordataxbenefitconsistentwiththeflow-throughmethod.Suchhasremainedsomewhatconstant,butits future increasesintaxespayablefromcustomersasthetemporarydif lower ratesasaresultofratecasesettlementthatoccurredduring2010. of thetemporarydif deduction forrepaircoststhatcontinuetobecapitalizedbookpurposes. The flow-throughadjustmentsrelateprimarilytoanaccountingmethodchangefortaxpurposesthatallowsustakeacurrent fective taxratedif resultedinadecreasetotaxexpense. Net OperatingLossCarryforward fective taxrateispredicatedonthelevelofpre-taxnetincomeasevidencedin201 ference createdbetweenbookandtaxtreatmentflowedthebenefitthroughtoourcustomersinformof Federal State fers fromthefederalstatutoryrateforyearsendedDec.31,asfollows: fect taxexpense. (a) valuationallowanceagainstthestateNOL The valuationallowanceadjustmentwasprimarilyattributabletoNOLswhose carryforwardswhichwillexpireatvariousdatesasfollows(inthousands): fset tothedeferredtaxasset.UltimateusageoftheseNOLsdependsuponour $ $ 164 Amounts ferences reverse. A regulatoryassetwasestablishedtoreflecttherecoveryof W 423,570 482,989 e recordedadeferredincometaxliabilityinrecognition 2013 As aresultofthisregulatorytreatment,we carryforwards. 34.7% 35.0% (0.9 (0.9 (0.5 (1.0 (0.1 0.7 2.4 — ) ) ) ) ) 2013 2019 1. $1.7 million 2012 Expiration Dates The re-evaluationofour 35.4% 35.0% (1.3 (1.3 (0.2 0.4 0.8 2.0 — — to to ofwhich$0.7 ) ) ) 2011 2033 2033 31.1% 35.0% (0.5 (4.5 (2.5 (0.5 (0.5 2.8 1.8 — ) ) ) ) ) FORM 10K ) ) ) 10K | 165 — — — 111 151 2,725 1,526
(3,533 (8,906 (4,578 50,135 49,327 40,683 37,631 Dec. $1.7 , 2012 and , based on the At Dec. 31, 2013, Positions Changes in Uncertain Tax Changes in $ $ e remain subject to 2007 to 2009. Such foreign tax 2015 and 2017. W fective tax rate is approximately fectuated in connection with the IPP of foreign tax credits to be included as for the years ended Dec. 31, 2013 e are currently under examination by the IRS for the e are currently under examination by the W $1.8 million fset United States federal income taxes. 165 and $1.4 million pre-tax of accrued interest associated with income taxes at pre-tax of accrued interest associated with The IRS has challenged our position with respect to the like-kind The IRS has challenged our position with $0.5 million, which expire between $8.3 million , $1.4 million valuation allowance against the foreign tax credit carryforwards. In addition, the valuation allowance against the foreign tax credit carryforwards. In addition, ficult to determine any reasonable estimate of the financial statement impact including ficult to determine any reasonable estimate of the financial statement impact including fset to liabilities for unrecognized tax benefits in recognition of the estimated impact the fset to liabilities for unrecognized tax benefits in recognition of the estimated $1.6 million . in income taxes attributable to the like-kind exchange ef in income taxes attributable to the like-kind ransaction that occurred in 2008. T $9.9 million pre-tax and fective tax rate. . Aquila $125 million . 1, respectively e have deferred a substantial amount of tax payments through various tax planning strategies including the deferral of tax payments through various tax planning strategies including the deferral of e have deferred a substantial amount of e recognized interest expense of e had approximately e file income tax returns with the IRS and various state jurisdictions. e file income tax returns with the IRS and Additions for prior year tax positions Additions positions for prior year tax Reductions year tax positions Additions for prior year tax positions Reductions for prior year tax positions Additions for current Settlements year tax positions Additions for prior year tax positions Reductions for prior Additions for current year tax positions Settlements ransaction and Ending balance at Dec. 31, 2011 Ending balance at Dec. 31, 2012 Ending balance at Dec. Ending balance at Dec. 31, 2013 Beginning balance at Jan. 1, 2011 Beginning T that the total unrecognized tax benefits attributable to such transaction could change exchange and it is reasonably possible before Dec. 31, 2014. However significantly due to a settlement with the IRS that is anticipated to occur on or information currently available, it is dif the impact on the ef Excess foreign tax credits have been generated and are available to of W approximately examination by Canadian income tax authorities for tax years as early as 1999. examination by Canadian income tax authorities we had foreign tax credit carryforwards of approximately As of Dec. 31, 2013, we had a $0.5 million carryforward balance reflects the expected utilization of approximately W The total amount of unrecognized tax benefits that, if recognized, would impact the ef The total amount of unrecognized tax benefits million 201 notification to audit the 2010 to 2012 tax years. 2007 to 2009 tax years and recently received tax years computational adjustments upon finalization of our current IRS examination covering credits have been reflected as an of resolution of material uncertain tax positions could have with respect to utilization. W W 31, 2013 and 2012, respectively The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the and end of beginning at the interest, without tax benefits, of unrecognized total amounts the table reconciles The following (in thousands): Sheets Balance Consolidated the accompanying on other liabilities credits and deferred in Other included period 166 |10K FORM 10K follows (inthousands): The componentsofthereclassificationadjustmentsforperiod,nettax,includedinOtherComprehensiveIncome wereas (15) carryforwards, theof filings. Ifthevaluationallowanceisadjustedduetohigherorlowerthananticipatedutilizationofstatetaxcredit attributable toanincreaseinforecastedapportionmentfactors.Ultimateusageofthesecreditsdependsuponourfuturetax the estimatedusefullifeofunderlyingassetthatgeneratedcredit. regulated businessandisbeingaccountedforunderthedeferralmethodwherebycreditsareamortizedtotaxexpenseover approximately our abilitytoutilizesuchcreditsresultedinadecreaseofthevaluationallowanceapproximately As ofDec.31,2013,wehada$0.8million following statetaxcreditcarryforwards(inthousands): State taxcreditshavebeengeneratedandareavailabletoof benefit plans,netoftax Total reclassificationadjustmentsrelatedtodefined Amortization ofdefinedbenefitplans: hedges, netoftax Total reclassificationadjustmentsrelatedtocashflow Gains andlossesoncashflowhedges: Income tax Actuarial gain(loss) Prior servicecost Income tax Commodity contracts Interest rateswaps Research anddevelopment Investment taxcredit OTHER COMPREHENSIVEINCOME $1.1 million State TaxCreditCarryforwards fsetting amountwillaf resultedinadecreasetotaxexpense. valuationallowanceagainstthestatetaxcreditcarryforwards. fect taxexpense. $ $ Income taxbenefit(expense) and maintenance Non-regulated energyoperations maintenance Utilities -Operationsand and maintenance Non-regulated energyoperations maintenance Utilities -Operationsand Income taxbenefit(expense) Revenue Interest expense 14,793 Location ontheConsolidated fset futurestateincometaxes. 155 166 Statements ofIncome The remaining The valuationallowanceadjustmentwasprimarily $1.5 million 2023 Expiration Years No expiration At Dec.31,2013,wehadthe to decreaseisattributabletoour $ $ $ $ Amount ReclassifiedfromAOCI Dec. 31,2013 2025 $2.6 million (2,016 2,538 1,098 1,693 1,655 4,046 6,062 6,989 (883 (128 (125 (927 The re-evaluationof ) ) ) ) ) $ $ $ $ Dec. 31,2012 ofwhich (1,177 (8,784 7,607 (643 534 — — — — — — — ) ) ) FORM 10K ) ) ) ) ) ) ) 10K | 167 9,854 (2,610 (1,525 18,066 37,529 (35,488 (32,878 (17,422 (35,488 (103,110 2011 Total Total The 401(k) $ $ $ $ $ $ $ $ 5 years of ) ) ) ) ) ) ) (699 9,486 5,743 -tax basis. (19,775 (19,076 (10,289 (19,775 (3,027 35,556 (116,593 2012 The 401(k) Plan provides Employee Employee $ $ $ $ (in thousands) Benefit Plans Benefit Plans $ $ $ $ ) ) ) ) ) 600 600 (508 1,235 4,338 (4,573 (3,738 (1,108 59,811 (108,361 2013 vesting when the participant has TION $ $ $ $ esting of all Company contributions ranges from V Derivatives Derivatives Commodity Commodity $ $ $ $ ) ) ) ) INFORMA 1,827 9,688 (6,625 167 (16,313 (18,140 (16,313 per year with 100 percent of their eligible compensation on a pre-tax or after CASH FLOW s age and years of service. Interest Rate Swaps Interest Rate Swaps Interest Rate Derivatives Designated as Cash Flow Hedges Derivatives Designated Derivatives Designated as Cash Flow Hedges Designated as Cash Derivatives $ $ $ $ Accumulated other comprehensive income (loss) on the accompanying Consolidated Consolidated accompanying on the income (loss) comprehensive other Accumulated 20 percent 50 percent PLANS DISCLOSURE OF . AL SUPPLEMENT EMPLOYEE BENEFIT e sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of e sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the Property, plant and equipment acquired with accrued liabilities Property, plant and equipment acquired Increase (decrease) in capitalized assets associated with asset retirement Increase (decrease) in capitalized assets obligations Income taxes, net Interest (net of amount capitalized) Other comprehensive income (loss) Other comprehensive As of Dec. 31, 2012 As of Dec. 31, 2011 Other comprehensive income (loss) income Other comprehensive As of Dec. 31, 2013 Years ended Dec. 31, As of Dec. 31, 2012 As of Dec. from continuing operations - Non-cash investing activities and financing Cash (paid) refunded during the period for continuing operations- Cash (paid) refunded during the period (16) Plan provides a Company Matching Contribution for all eligible participants and for certain eligible participants a Company Plan provides a Company Matching Contribution for all eligible participants and Retirement Contribution based on the participant’ immediate vesting to graduated vesting at W by the IRS. their eligible compensation to the 401(k) Plan up to the maximum amounts established (17) Defined Contribution Plans employees the opportunity to invest up to service with the Company Balances by classification included within included by classification Balances Balance Sheets were as follows (in thousands): (in were as follows Sheets Balance 168 |10K FORM 10K long-term rateofreturnforinvestmentswas not fundedbytheCompany and definedcontributionplans (SupplementalPlans). W Supplemental Non-qualifiedDefinedBenefitPlans The percentagesoftotalplanassetfairvaluebyinvestmentcategoryforourPensionPlansatDec.31wereasfollows: Plan into theBHCPensionPlan. amendment wasef In 201 Pension Planfundingpolicyisinaccordancewiththefederalgovernment’ payment obligations. assets aremanagedbyanoutsideadviserusingaportfoliostrategythatwillprovideliquiditytomeetthePlans’ that willallowtheeventualsettlementofourobligationstoPensionPlans’ Directors hasapprovedthePlans’ Pension PlanassetsareheldinaMaster were frozen. frozen tonewemployeesandcertainwhodidnotmeetageservicebasedcriteriaatthetimePension Plans calculations ofaverageearningsduringaspecifictimeperiodpriortoretirement. certain eligibleemployeesofBlackHillsEner Company W Defined BenefitPensionPlans(PensionPlans) status ofourNon-pensionDefinedBenefitPostretirementHealthcarePlanswas $41 million measurement dateforallplansis periodic benefitcostwasalternativelyrecordedasaregulatoryassetorliability (loss), netoftax.Forourregulatedutilities,thesecostsarerecoverableinrates,andaccordingly our regulatedutilities,theunrecognizednetperiodicbenefitcostisrecordedwithin assets oranassetisrecordedforanyamountbywhichthefairvalueofplanexceedsbenefitobligation.Except fair valueofplanassets. The fundedstatusforallotherbenefitplansismeasuredasthedif status forpensionplansismeasuredasthedif The fundedstatusofpostretirementbenefitplansisrequiredtoberecognizedinthestatementfinancialposition. Funded StatusofBenefitPlans e havevarioussupplemental retirement plansforkeyexecutivesoftheCompany e havetwodefinedbenefitpensionplans.OurBHCPensionPlancoverscertaineligibleemployeesofBlackHillsService Assets 1, theCheyenneLightPensionPlanwasamendedtofreezebenefitsofcertainbar , BlackHillsPower ; theunfundedstatusofourSupplementalNon-qualifiedDefinedBenefitPlanswas fective asof The PensionPlans’ A liabilityisrecordedforanamountbywhichthebenefitobligationexceedsfairvalueofplan . The PensionPlanbenefitsarebasedonyearsofserviceandcompensationlevels. , WRDC, BHEP Jan. 1,2012. investmentpolicy Dec. 31. Hedge funds Cash Fixed income Real estate Equity Total T assetsconsistprimarilyofequity rust. EachPlanholdsanundividedinterestintheMaster As ofDec.31,2013,theunfundedstatusourDefinedBenefitPensionPlanswas Additionally 7.25 percentand andCheyenneLight. ference betweentheprojectedbenefitobligationandfairvalueofplanassets. gy . The benefitsforthePensionPlansarebasedonyearofserviceand . The objectiveoftheinvestmentpolicyistomanageassetsinsuchaway The SupplementalPlansaresubject tovariousvestingschedulesandare , ef fective 7.25 percentforthe 168 2013 ference betweentheaccumulatedbenefitobligationand The BlackHillsUtilityHoldings,Inc.PensionPlancovers Oct. 1,2012,theCheyenneLightPensionPlanwasmer 100% 11 58 26% 1 4 , fixedincomeandhedgedinvestments. s fundingrequirements. beneficiaries. $41 million As ofJan.1,2010,bothPensionPlanswere 2013 and2012planyears,respectively . 2012 Accumulated othercomprehensiveincome The plansarenon-qualifieddefined benefit 100% — 44 47% , netoftax(seeNote 1 8 gaining unitemployees. . T o meetthisobjective,ourpension $33 million T , theunrecognizednet rust. OurBoardof ; andtheunfunded benefit 1). The expected The The funded This . Our ged FORM 10K 10K | 169
2,639 8,981 5,191 1,270 25,350 A 2012 2012 $ $ $ $ $ s assessment of the 8,524 2,775 5,123 1,345 12,500 2013 2013 fect their placement within the rust accounts. Healthcare and $ $ T $ $ $ The Company’ gy Plan provides for partial pre-funding gy Plan provides for 2014. The Black Hills Ener e do not pre-fund the Postretirement Healthcare Plans for those Postretirement Healthcare Plans for those e do not pre-fund the 169 W fective Jan. 1, 2014, health care coverage for Medicare-eligible health care coverage for Medicare-eligible fective Jan. 1, 2014, e Plans VEBAs. Ef e fund on a cash basis as benefits are paid. a cash basis as benefits e fund on W ement Healthcar etir ements gy located in the states of Kansas and Iowa. gy located in the states Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees of the benefit of the union and non-union pre-funding are held in trust and are for Assets related to this alue Measur V Assets Assets
VEBAs. e sponsor three retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at age and service who meet certain Plans) for employees plans (Healthcare three retiree healthcare e sponsor e fund the Healthcare Plans on a cash basis as benefits are paid. Plans on a cash basis as benefits are e fund the Healthcare e do not anticipate making contributions to our Pension Plans in e do not anticipate making contributions e do not fund our Supplemental Plans. our Supplemental e do not fund Matching contributions - Defined Contribution Plans Matching contributions - Defined Contribution Defined Benefit Plans Defined Benefit Pension Plans Defined Contribution Plan Company Retirement Contribution Non-Pension Defined Benefit Postretirement Healthcare Plans Non-Pension Defined Benefit Postretirement Plans Supplemental Non-Qualified Defined Benefit W limitations. and other co-payment provisions premiums, deductibles, are subject to Healthcare Plan benefits retirement. W Plan via Black Hills Ener W Contributions to the Pension Plans are cash contributions made directly to the Pension Plan Contributions to the Pension Plans are Plan W Plan Contributions Non-pension Defined Benefit Postr Defined Benefit Non-pension Utility Holdings retirees. care exchange for BHC and Black Hills through an individual market health retirees will be provided and Iowa. employees outside Kansas portion of the Healthcare Plans is pre-funded via portion of the Healthcare were as in the form of benefit payments. Contributions for the years ended Dec. 31 Supplemental Plan contributions are made follows (in thousands): Fair assets and liabilities are classified in their As required by accounting standards for Compensation - Retirement Benefits, entirety based on the lowest level of input that is significant to the fair value measurement. and may af significance of a particular input to the fair value measurement requires judgment, fair value hierarchy levels. 170 |10K FORM 10K recurring basis(inthousands): The followingtablessetforth,bylevelwithinthefairvaluehierarchy Total investmentsmeasuredatfairvalue Mutual Fund Registered InvestmentCompanyTrust-MoneyMarket Plans Non-pension DefinedBenefitPostretirementHealthcare Total investmentsmeasuredatfairvalue Mutual Fund Registered InvestmentCompanyTrust-MoneyMarket Plans Non-pension DefinedBenefitPostretirementHealthcare Total investmentsmeasuredatfairvalue Structured Products Common CollectiveTrust-RealEstate Common CollectiveTrust-FixedIncome Common CollectiveTrust-Equity Common CollectiveTrust-CashandEquivalents Money MarketFund Defined BenefitPensionPlans Total investmentsmeasuredatfairvalue Hedge Funds Common CollectiveTrust-RealEstate Common CollectiveTrust-FixedIncome Common CollectiveTrust-Equity Common CollectiveTrust-CashandEquivalents AXA EquitableGeneralFixedIncome Defined BenefitPensionPlans $ $ $ $ $ $ $ $ 170 Level 1 Level 1 Level 1 Level 1 1,486 1,486 , theassetsthatwereaccountedforatfairvalueona — — — — — — — — — — — — — — — — $ $ $ $ $ $ $ $ Level 2 Level 2 Level 2 Level 2 259,560 242,174 114,440 126,105 162,747 13,361 73,726 4,351 4,351 4,546 4,546 1,056 4,536 1,118 3,392 1,253 Dec. 31,2012 Dec. 31,2013 Dec. 31,2012 Dec. 31,2013 — — $ $ $ $ $ $ $ $ Level 3 Level 3 Level 3 Level 3 38,188 29,647 7,770 7,770 8,541 — — — — — — — — — — — — — $ $ $ $ $ $ $ $ Total Total Total Total 268,816 280,362 114,440 126,105 162,747 21,131 29,647 11,933 73,726 4,351 4,351 4,546 4,546 1,486 1,056 4,536 1,118 1,253 FORM 10K , 10K | 171 — — — 727 7,043 7,770 2012 N/A N/A Average $ $ ) ) Range (Weighted) The fair value of Level 3 assets for 3 assets Level The appraisals are (77 (13 7,770 1,508 . 29,000 38,188 . 2013 Appraisal Institute, with the $ $ Input Level 3 Redemption Restriction Redemption Restriction reasury rate with a like term. T rustee along with the annual schedule of investments and rustee along with the annual schedule of investments T The fair value of privately placed securities are Valuation Technique underlying assets. Unit values are determined by the Market Approach Market Approach s net assets at fair value by its units outstanding at the valuation 171 8,541 29,647 rust - Real Estate fund is determined by appraisal of the properties held in the rust - Real Estate fund is determined by appraisal T All external appraisals are performed in accordance with the Uniform Standards All external appraisals are performed in accordance The fund does contain a participant withdrawal policy The fund does contain a participant withdrawal Fair Value at Dec. 31, 2013 These models use observable inputs with a discount rate based upon the $ $ This fund is a diversified portfolio, primarily composed of fixed income This fund is a diversified portfolio, primarily : (a) e receive monthly statements from the Appraisal Institute. W , rustee's valuation process, properties are externally appraised generally on an annual basis. rustee's valuation process, properties are externally , the audited financial statements of the funds will be reviewed at the time they are issued. , the audited financial statements of the funds T rust - Real Estate These funds are valued based upon the redemption price of units held by the Plan, which is rust Funds: These funds are valued based upon the redemption price of units held by the Plan, T Appraisal Practices. s investments in common collective trust funds, with the exception of shares of the common collective trust- s investments in common collective trust funds, with the exception of shares of The discount rate is derived from taking the appropriate U.S. (b) Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly Assets are invested in long-term holdings, such as commercial, agricultural and Additionally As part of the The Plan’ rust. Equitable General Fixed Income Fund rely on these reports for pricing the units of the fund. rely on these reports for pricing the units of on pricing provided or reviewed by third-party administrator to our investment managers. The fair value of Level 3 is determined based vendor in determining fair value are not provided, and therefore, unavailable for our review While the input amounts used by the pricing T of Professional conducted by reputable independent appraisal firms and signed by appraisers that are members of the conducted by reputable independent appraisal professional designation of Member to ensure the fair values are reasonable and in line with market experience in similar asset the asset results are reviewed and monitored classes. The underlying net asset value in the Common Collective The underlying net asset value in the Common Balance, beginning of period Balance, beginning Purchase Unrealized gain (loss) Realized gain (loss) Settlements Balance, end of period Assets: Common Collective Hedge Funds (b) valuation service provides with public fixed maturity securities are generally based on prices obtained from independent reasonableness prices compared with directly observable market trades. determined using a discounted cash flow model. sector of the issuer average of spread surveys collected from private market intermediaries and industry Common Collective T based on the current fair value of the common collective trust funds’ financial institution sponsoring such funds by dividing the fund’ dates. real estate are categorized as Level 2. instruments. values of mortgage loans are measured by traded and privately place bonds and real estate as well as short-term bonds. Fair using interest rates at which loans with similar discounting future contractual cash flows to be received on the mortgage loans characteristics. AXA Additional information about assets of the Pension Plans, including methods and assumptions used to estimate the fair value of the Pension Plans, including methods and assumptions used to estimate the fair Additional information about assets of these assets, is as follows: ______(a) the period ended Dec. 31 (in thousands): Dec. 31 ended the period (dollars in thousands): Level 3 fair value measurements presents the quantitative information about The following table The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plans’ Benefit Defined value of the in the fair changes of forth a summary table sets The following 172 |10K FORM 10K (a) Benefit Obligations comprehensive income(inthousands): recognized inthestatementoffinancialposition,componentsnetperiodicexpenseandelementsaccumulated other The followingtablesprovideareconciliationoftheemployeebenefitplanobligations,fairvalueassetsandamounts Other individual securitiesaretraded. Register swaps isdeterminedby(respectively securities likeequity Structur are nounfundedcommitmentsrelatedtothesehedgefunds. total netassetvalueofthefund. redeemed attheendofeachquarter using netassetvaluepersharebasedonthefairofhedgefund’ returns underallmarketconditions. investment strategies. Hedge Funds:fundsrepresentinvestmentsinotherinvestmentthatseekareturnutilizingnumberofdiverse categorized asLevel3. reports forpricingtheunitsoffund.Certainfunds’ Practices. Appraisal Institute. appraisal firmsandsignedbyappraisersthataremembersofthe properties areexternallyappraisedgenerallyonanannualbasis. properties, includingmarketrent,rentgrowth,occupancylevels,etc. Common CollectiveT ______Benefits paid Actuarial (gain)loss Interest cost Service cost beginning ofyear Projected benefitobligationat Change inbenefitobligation: year Projected benefitobligationatendof Plan participants’contributions Medicare PartDaccrued Plan curtailmentliabilityreduction Amendments Reflects BoardofDirectorsapproval ofanincreasetoCompany’ PlanInformation ed Pr ed InvestmentCompanies:Investmentsarevaluedattheclosingpricereportedonactivemarketwhich W e receivemonthlystatementsfromthetrustee,alongwithannualscheduleofinvestments,andrelyonthese oducts: Investmentsarecreatedthroughtheprocessoffinancialengineering,(thatis,bycombiningunderlying (a) All externalappraisalsareperformedinaccordancewiththeUniformStandardsofProfessional , bonds,orindiceswithderivatives). rust-Real EstateFund The strategies,whencombinedaimtoreducevolatilityandriskwhileattemptingdeliverpositive The fundswithoutparticipantwithdrawallimitationsarecategorizedasLevel2. The netassetvaluesarebasedonthefairvalueofeachfund’ , afteralockupperiodofone-year Amounts arereportedonaone-monthlag. , derivesfrom)thepricesofunderlyingsecurities. $ $ Defined BenefitPension : This fundisvaluedbasedonvariousfactorsoftheunderlyingrealestate 2013 363,235 321,400 (25,316 (38,252 15,300 6,433 — — — — Plans ) ) $ $ The valueofderivativesecurities,suchasoptions,forwardsand 2012 assetscontainparticipantwithdrawalpolicyand,therefore,are 325,944 363,235 (11,815 14,747 28,639 172 s contributiontoRMSA 5,720 The appraisalsareconductedbyreputableindependent Appraisal Institute,withprofessionaldesignationofMember — — — — ) , witha65daynoticeandislimitedtopercentageof $ $ Benefit RetirementPlans s underlyinginvestments.Generally Nonqualified Defined 2013 As partofthetrustee’ 34,393 32,960 (1,345 (2,808 Supplemental 1,328 1,392 The fairvalueofhedgefundsisdetermined — — — — ) ) accounts. $ $ 2012 30,223 34,393 (1,269 1,410 3,140 s underlyinginvestments. 889 — — — — ) s valuationprocess, $ $ Benefit Postretirement Non-pension Defined 2013 46,681 45,778 (5,123 (3,379 1,585 1,669 1,674 2,201 , sharesmaybe 470 — Plans ) ) $ $ Appraisal 2012 There 50,141 46,681 (5,190 (4,430 2,093 1,610 2,168 289 — — , ) ) FORM 10K ) ) 10K | 173 (3 — 4,351 6,438 2,573 2,174 8,504 4,319 2,172 1,458 (3,595 39,807 12,309 25,868 46,681 fering. 2012 2012 2012 (a) $ $ $ $ $ $ $ $ ) 8 — Plans 4,546 5,535 2,802 3,141 8,210 4,351 1,923 1,533 (3,269 38,412 12,101 25,467 45,778 Healthcare Plans Healthcare Plans 2013 2013 2013 Non-pension Defined Non-pension Defined Non-pension Defined Defined Non-pension Benefit Postretirement Benefit Postretirement Benefit Postretirement Benefit Postretirement $ $ $ $ $ $ $ $ — — — — — — — — — — 453 1,286 33,180 28,056 28,509 2012 2012 2012 $ $ $ $ $ $ $ $ — — — — — — — — — — 513 Benefit Plans Benefit Plans Supplemental Supplemental 1,491 Supplemental 32,033 27,380 27,893 2013 2013 2013 Non-qualified Defined Non-qualified Defined Nonqualified Defined Nonqualified Benefit Retirement Plans Benefit Retirement $ $ $ $ $ $ $ $ ) — — — — — 173 94,199 94,410 33,559 25,350 (11,815 268,816 124,143 202,897 327,040 221,722 2012 2012 2012 $ $ $ $ $ $ $ $ Plans Plans (b) — — — ) Plans — — 48,419 41,034 110,847 182,295 293,142 2013 2013 24,362 12,500 Defined Benefit Pension Defined Benefit Pension (25,316 280,362 268,816 $ $ $ $ $ $ 2013 Defined Benefit Pension Defined Benefit payment made to terminated vested employees who elected a lump-sum of vested employees who elected a lump-sum $13 million payment made to terminated $ $ VEBA 2013 Benefits paid includes a one-time 2013 Benefits paid includes Assets of reconciliation of the fair value of Plan assets was as follows (in thousands): (in was as follows Plan assets value of of the fair reconciliation Plan administrative expenses Plan administrative of plan assets Ending market value Regulatory assets Current liabilities Non-current liabilities Regulatory liabilities Accumulated benefit obligation - Black Hills Corporation Accumulated benefit obligation - Black Hills Energy Accumulated benefit obligation - Cheyenne Light Total Accumulated Benefit Obligation (in thousands) Beginning market value of plan Beginning assets (loss) Investment income Employer contributions Retiree contributions Benefits paid ______Accumulated Benefit Obligation (b) Balance Sheets at Dec. 31 consist of (in thousands): Amounts recognized in the Consolidated (a) A 174 |10K FORM 10K Assumptions expected toberecognizedasacomponentofnetperiodicbenefitcostduringcalendaryear The amountsin (in thousands): income (loss),after In accordancewithaccountingstandardsfordefinedbenefitplans,amountsincludedin Accumulated OtherComprehensiveIncome Components ofNetPeriodicExpense levels Rate ofincreaseincompensation Discount rate obligations: used todeterminebenefit Weighted-average assumptions recognized duringcalendaryear2014 Total netperiodicbenefitcostexpectedtobe Prior servicecost(credit) Net loss (income) loss Total accumulatedothercomprehensive Prior servicecost(gain) Net (gain)loss Net periodicexpense Curtailment expense (gain) Recognized netactuarialloss Amortization ofpriorservicecost Expected returnonassets Interest cost Service cost (in thousands) Accumulated othercomprehensiveincome(loss),Regulatoryassetsorliabilities,after -tax, thathavenotyetbeenrecognizedascomponentsofnetperiodicbenefitcostatDec.31werefollows $ $ (18,615 15,431 12,250 15,300 2013 2013 Defined BenefitPension Defined BenefitPension 3.78 5.05 6,433 — 63 $ $ Defined BenefitPension % % ) 2013 $ $ (16,334 13,852 14,747 Plans Plans 2012 2012 3.84 4.30 9,630 5,720 4,906 4,842 $ $ 64 — 89 Plans % % ) Defined Benefit Pension Plans $ $ $ $ (16,955 14,929 2011 2011 3.77 4.65 8,047 4,540 5,421 2012 12,168 12,090 174 13 99 % % ) 78 $ $ 2013 2013 3,165 3,124 5.00 4.21 3,515 1,328 1,392 Non-qualified Defined Non-qualified Defined $ $ 793 41 — — Non-qualified Defined 2 % % Supplemental Supplemental Benefit Plans Benefit Plans 2013 $ $ $ $ 4,948 4,939 Supplemental Benefit Plans 2012 2012 Supplemental Non- 5.00 3.44 3,109 1,410 qualified Defined 807 889 Benefit Plans 9 — — 3 % % $ $ $ $ Accumulated othercomprehensive 2012 2011 2011 5.00 4.30 2,839 1,298 1,028 2014 areasfollows(inthousands): 510 7,294 7,283 — — 3 % % 11 324 323 $ $ 1 2013 2013 $ $ 4.62 3,246 1,669 1,674 Benefit Postretirement Benefit Postretirement Non-pension Defined Non-pension Defined (500 Benefit Postretirement N/A Non-pension Defined 482 $ $ (79 Benefit Postretirement 2013 Healthcare Plans Healthcare Plans — Non-pension Defined Healthcare Plans % (1,213 Healthcare Plans ) ) 1,648 $ $ 435 2012 2012 4,012 2,093 1,610 3.85 (500 N/A ) 887 (78 -tax, — $ $ % ) ) 2012 $ $ 2011 2011 (1,784 3,700 2,168 1,498 4.42 2,097 (119 (218 (479 (164 N/A 313 677 99 — % ) ) ) ) ) FORM 10K 10K | 175 % % % % NA 2027 2026 2027 2026 7.50% 4.50% 6.25% 4.50% 7.75% 4.50% 6.50% 4.50% 5.00 4.00 4.60 5.50 2011 % % % % NA 4.35 2.00 4.35 4.65 2012 Cheyenne Light % % % % Healthcare Plans Healthcare NA 2027 2026 2027 2026 7.50% 4.50% 6.25% 4.50% 7.75% 4.50% 6.50% 4.50% Non-pension Defined Non-pension Benefit Postretirement 3.65 2.00 3.50 4.40 2013 Energy % % % Black Hills N/A N/A 5.00 5.00 4.40 2011 % % % 2027 2026 2027 2026 7.50% 4.50% 6.25% 4.50% 7.75% 4.50% 6.50% 4.50% N/A N/A 4.70 5.00 3.90 2012 2014 net periodic pension cost. Benefit Plans Supplemental % % % Black Hills Corporation N/A N/A Non-qualified Defined Non-qualified 3.88 5.00 3.00 2013 % % % % % 175 5.50 7.75 3.79 5.40 5.55 2011 for the calculation of the % % % % N/A 4.68 7.25 3.75 4.60 2012 Plans 6.75 percent % % % % N/A 4.35 7.25 3.78 4.25 Defined Benefit Pension Defined Benefit 2013 (a) The expected rate of return on plan assets is The expected rate of return on plan assets is Trend for next year Ultimate trend rate Year Ultimate Trend Reached Trend for next year Ultimate trend rate Year Ultimate Trend Reached Trend for next year Ultimate trend rate Year Ultimate Trend Reached Trend for next year Ultimate trend rate Year Ultimate Trend Reached Black Hills Corporation Black Hills Energy Cheyenne Light 2013 Healthcare trend rate pre-65 Weighted-average assumptions Weighted-average net periodic used to determine for plan year: benefit cost Discount rate: Rate of increase in compensation levels Healthcare trend rate post-65 Expected long-term rate of return Expected long-term on assets 2012 Healthcare trend rate pre-65 Healthcare trend rate post-65 ______The healthcare benefit obligation was determined at Dec. 31 as follows: The healthcare benefit obligation was determined (a) 176 |10K FORM 10K parties: Through oursubsidiaries,wehavethefollowingsignificantlong-termpowerpurchasecontractswithnon-af Power (18) The followingbenefitpayments,whichreflectfutureservice,areexpectedtobepaid(inthousands): expected impactsofanincreaseordecreasetoourhealthcaretrendrateforRetireeHealthcarePlans(inthousands): W 2019-2023 2018 2017 2016 2015 2014 Decrease 1% Increase 1% e donotpre-fundournon-qualifiedpensionplansortwoofthethreepostretirementbenefitplans. • • • • • • • Pur Change inAssumedTrendRate will receive Cheyenne Lightrenewedand receivedFERCapprovalforanagreementwithBasinElectric wherebyCheyenneLight the BuschRanch Colorado Electric’ economy ener Colorado Electric’ megawatts ofener megawatts ofwindener Cheyenne Light’ 50 percentofthefacilityoutputtoBlackHillsPower of windener Cheyenne Light’ 2023. Black HillsPowerhasafirmpoint-to-pointtransmissionserviceagreementwithPacifiCorpthatexpires costs ofonePacifiCorp’ capacity andener Black HillsPower COMMITMENTS chase and The agreementprovides 40 megawattsofcapacityandener gy fromHappyJacktoCheyenneLight.Underaseparateinter T gy ransmission Services . s PP s PP gy fromPacifiCorp’ W gy fromSilverSagetoBlackHillsPower s REP s PP ’ s PP ind ProjectinwhichColoradoElectricownsa AND CONTINGENCIES A A $ $ $ $ $ $ A withDukeEner withDukeEner A gy withCar A withPacifiCorp,expiring Defined Benefit with . Underaseparateinter Pension Plans s coal-firedelectricgeneratingplants. 50 megawattsofcapacityandener AltaGas expiringOct.16,2037,providesupto gill expiring 105,252 Agr s system. 17,627 16,562 15,608 14,572 13,721 gy’ gy’ eements s SilverSagewindsite,expiring s HappyJackwindsite,expiring $ $ Dec. 31,2014,wherebyColoradoElectricpurchases gy fromBasinElectricthrough Accumulated Postretirement The pricepaidforthecapacityandener $ $ $ $ $ $ Impact onDec.31,2013 -company agreement,CheyenneLighthasagreedtosell20 Supplemental Non-qualified Dec. 31,2023,forthepurchaseof Benefit Obligation . 176 Defined BenefitPlan . gy tobetransmittedannuallybyPacifiCorp. 50 percent (1,644 1,914 Sept. 30,2029,providesupto -company agreement,CheyenneLightsells Sept. 3,2028,providesupto30megawatts undividedownershipinterest. 8,146 1,622 1,588 1,542 1,490 1,491 Sept. 30,2014. ) 14.5 megawattsofwindener $ $ $ $ $ $ $ $ 50 megawattsofelectric Impact on2013Service gy isbasedontheoperating Non-Pension DefinedBenefit Postretirement Healthcare and InterestCost The tablebelowshowsthe filiated third- Plans 50 megawattsof Dec. 31, 30 gy from (116 136 17,520 3,572 3,495 3,477 3,397 3,340 ) FORM 10K 10K | 177 — e - W 1,215 1,955 3,281 . 12,515 97,988 The sale 2011 A. August 2014. $ $ $ $ $ $ gy PP The agreement — 502 1,215 1,988 3,269 100 percent and 75 13,224 were to support an inter first quarter of 2014 2012 $ $ $ $ $ $ needs, under short-term and long- needs, under short-term — with Cheyenne Light in 1,384 3,772 4,809 1,856 13,026 A 2013 203,131 148,874 136,503 125,492 110,930 148,362 $ $ $ $ $ $ . Construction is expected to be completed by Sept. $ $ $ $ $ $ $222 million 177 is being accounted for as a capital lease. is being accounted for A , upon expiration of the PP The contract requires us to deliver a minimum of 20,000 Mcf per The contract requires us to deliver a minimum The facilities constructed by Black Hills Colorado IPP The facilities constructed 2017. -company PP $22 million 1 and was replaced with the facilities constructed by Colorado Electric and Black Hills the facilities constructed by Colorado Electric 1 and was replaced with 2015 2016 2017 2018 Thereafter 2014 This inter yoming will provide services to the City of Gillette through an economy ener yoming entered into an agreement to sell its 40 megawatt CTII natural gas-fired generating unit yoming entered into an agreement to sell its 40 megawatt CTII natural gas-fired W . Airport Generation site. Airport Generation site. W These contracts extend to yo. for approximately eements W Agr eement with Colorado Electric. with Colorado Electric. at our Pueblo (a) A Agr with PSCo expired on Dec. 31, 201 with PSCo expired on A fective when the infrastructure is placed in commercial service, which we estimate to be fective when the infrastructure is placed As of Dec. 31, 2013, committed contracts for equipment purchases and for construction were As of Dec. 31, 2013, committed contracts for equipment purchases and for construction complete, respectively Gas Supply e Minimum Payments with PSCo The gatherer is in the process of building the necessary infrastructure to handle the committed volumes. The gatherer is in the process of building Colorado IPP company PP This PP chase Sale . A PPA with PacifiCorp PPA with PP with PacifiCorp services agreement Transmission Happy Jack PPA with PPA with Silver Sage Project Busch Ranch Wind Pur As part of the sale, Black Hills 30, 2014. On May 6, 2013, Black Hills to the City of Gillette, The following is a schedule of future minimum payments required under the power purchase, transmission services, coal and payments required under the power purchase, transmission services, The following is a schedule of future minimum delivery commitments (in thousands): gas supply agreements, and natural gas facility jointly owned by Cheyenne Construction of Cheyenne Prairie, a 132 megawatt natural gas-fired electric generating Light and Black Hills Power is expected to cost approximately Futur Construction Obligations believe that our reserves dedicated to the gathering system, and the projected volumes are adequate to satisfy our delivery gathering system, and the projected volumes are adequate to satisfy our delivery believe that our reserves dedicated to the commitments under this agreement. is subject to FERC approval and certain other requirements included in the contract. percent becomes ef day Other capacity to meet customers’ natural gas, including transportation Our Utilities also purchase (a) Basin gathering contract for natural gas production from our properties in the Piceance In 2012, we entered into a ten-year gas fee per Mcf. in Colorado, under which we pay a gathering ______term purchase contracts. Natural Gas Delivery Commitment Costs under these power purchase contracts for the years ended Dec. 31 were as follows (in thousands): (in as follows Dec. 31 were ended for the years contracts purchase power under these Costs 178 |10K FORM 10K regulation andenforcementoversight byvariousgovernmentalagencies. Power generatingfacilitiesburning fossilfuelsemiteachoftheforegoingpollutantsand, therefore,aresubjecttosubstantial These lawsandregulationscover Our generationfacilitiesaresubjecttofederal,stateandlocal lawsandregulationsrelatingtotheprotectionofairquality Air remediation andmonitoringobligations.Duetotheenvironmental issuesdiscussedbelow existing operations. W Envir corporate consolidations. associated withthePP related leaseobligationandBlackHillsColoradoIPP whereby ColoradoElectric,aslessee,hasincludedthecombined-cycleturbinesproperty Colorado ElectricfromBlackHillsIPP’ Colorado Electric’ Related PartyLease Through oursubsidiaries,wehavethefollowingsignificantlong-termpowersalescontractswithnon-af Power for capitaladditionsandreducedbyanamountequaltoannualdepreciationbasedona35-yearlifestartingJan.1,2009. construction estimatedcostofthe I facility expiring onDec.31,2022 Cheyenne Light’ Futur regulatory bodies. curtail, replaceorceaseoperatingcertainfacilitiesoperations tocomplywithstatutes,regulationsandotherrequirementsof e aresubjecttocostsresultingfromanumberoffederal,state andlocallawsregulationswhichaf • • • • • onmental Matters e Pur Sales . plants. megawatts fromNeilSimpsonIIandupto Black HillsPowerhasaPP of unit-contingentcapacityfromNeilSimpsonIIand Black HillsPowerhasaPP will provide Cheyenne LightrenewedandreceivedFERCapprovalforanagreementwithBasinElectricwhereby agreement, BlackHillsPowerwillalsoprovidetheCityofGillettetheiroperatingcomponentspinningreserves. other generatingfacilitiesorfromsystempurchaseswithreimbursementofcostsbytheCityGillette.Underthis during periodswhen During periodsofreducedproductionat system purchaseswithreimbursementofcostsbyMDU. when During periodsofreducedproductionat The purchasepricerelatedtotheoptionis chase Agr W The capacitypurchaserequirementsdecreaseoverthetermofagreement. s PP ygen IIIisof eements Agr s PP They canresultinincreasedcapitalexpenditures,operating andothercostsasaresultofcompliance, A 40 megawattsofcapacityandener A eement -RelatedParty A for60megawattsofcapacityandener havebeenimpactedbytheleaseaccounting. withBlackHillsColoradoIPP , includesanoptionforCheyenneLighttopurchaseBlackHills W f-line, MDUwillbeprovidedwith ygen IIIisof , amongotherpollutants,carbon monoxide,SO W A A ygen IIIplant,whichwascompletedin withMEANexpiringMay31,2023. withMEANexpiring f-line, wewillprovidetheCityofGillettewithitsfirst W W s combined-cycleturbines. ygen IIIinwhichtheCityofGilletteownsaportioncapacity ygen IIIinwhichMDUownsaportionofthecapacity $2.6 millionpermegawattwhichistheequivalentofpre- 10 megawattsfrom , aslessor expiringonDec.31,2031,provides gy toBasinElectricthrough April 1,2015.Underthiscontract,MEANpurchases gy fromBlackHills 178 5 megawattsofunit-contingentcapacityfrom , hasrecordedaleasereceivable.Segmentrevenueandexpenses 25 megawattsfromourothergenerationfacilitiesor The ef W ygen IIIbasedontheavailabilityofthese This contractisunit-contingentonupto April 2010. fect oftheleaseaccountingiseliminatedin This PP 2 , NO W yoming’ A Sept. 30,2014 x isaccountedforasacapitallease , mercuryparticulatematterand GHG. This optionpurchasepriceisadjusted , wemayberequiredtomodify W , plantandequipmentalongwiththe s 200 megawattsofpowerto yoming’ W ygen Igeneratingfacility . 23 megawattsfromour s ownershipinthe fect futureplanningand filiated third-parties: , orduringperiods W ygen III. 5 megawatts 10 , or W , . ygen FORM 10K 10K | 179 ge II, Act The Air to $6.3 While we $2.9 million of the Clean of the , we can provide no oluntary Cleanup V itle IV Air Pollutants, with updates Air Pollutants, T The reclamation liability is ground water The acquisition provided for an ithout purchasing additional allowances, additional allowances, ithout purchasing W Agreement with the successor to the former Act, the CPUC issued an order approving the Act, the CPUC issued The rule has a compliance deadline of March a compliance deadline The rule has Access Area Sources of Hazardous Area Sources e plan to retire Ben French, Osage and Neil Simpson I on e plan to retire Ben Air Clean Jobs W An application to close the impoundment was approved on the impoundment was approved on An application to close . sites currently range from approximately Airport Generating Station plants. plants. Station Generating Airport This facility suspended operations Dec. 31, 2012 and was retired operations Dec. 31, 2012 and was This facility suspended 179 with the State of Colorado to cover the costs of $3.9 million with the State of Colorado to cover the at all such plants through 2043. at all such The remediation cost estimate could change materially due to results of itle IV Aug. 31, 2012. T recorded in Other assets, non-current on our Consolidated Balance Sheets, yodak and Pueblo and Pueblo yodak Allocation, Indemnification and W accrued for remediation of sites as of Dec. 31, 2013 included in Other deferred credits accrued for remediation of sites as of Dec. 31, 2013 included in Other deferred ygen III, ygen W fset remediation costs. ransaction, we acquired whole and partial liabilities for several former manufactured gas processing ransaction, we acquired whole and partial liabilities for several former manufactured WRDC is required to reclaim all land where it has mined coal reserves. WRDC is required to reclaim all land where Act applies to several of our generation facilities, including the Neil Simpson II, Neil Simpson CT Simpson II, Neil Neil Simpson the including facilities, our generation several of to Act applies T ocessing ygen II, ygen ficient allowances to satisfy ficient allowances Air W , now valued at $1.3 million While the net book value of these plants is estimated to be immaterial at the time of retirement, we would immaterial at the time of retirement, we value of these plants is estimated to be While the net book Aquila .N. Clark facility no later than Dec. 31, 2013. .N. Clark facility no Airport Generation site, we posted a bond of Airport Generation site, we posted a bond allowance trading program as part of the federal acid rain program. acid rain program. part of the federal trading program as allowance W 2 1, Nebraska Gas executed an ygen I, ygen ed Gas Pr W , issued the Industrial and Commercial Boiler Regulations for Boiler Regulations Industrial and Commercial issued the The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. The reclamation liability is recorded at of the Clean of the aste Disposal for which we had $2.9 million A . .N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. .N. Clark plant, which has been retired, W arious materials used at our facilities are subject to disposal regulations. Our Osage plant, at which operations have been regulations. Our Osage plant, at which at our facilities are subject to disposal arious materials used itle IV created an SO created an For our Pueblo Reclamation Liability on Dec. 31, 2013. a disallowance of the remaining value. reasonably not expect dischar pond permitted to provide wastewater storage and processing for this zero remediation for a waste water containment V ash impoundment that is near capacity suspended, has an on-site Electric is required to reclaim all land where it has placed wind turbines. Under its land lease for Busch Ranch, Colorado Manufactur Solid W Our Under its mining permit, See Note 7 for additional information. Lange CT Lange hold suf we currently and monitoring requirements. fuel requirements emission limits, which impose of this rule, we 2010 and as a result Osage plant in October operations at the rule we suspended In anticipation of this 21, 2014. at the Ben French facility on suspended operations Clean 2014. In conjunction with the Colorado or before March 21, closure of the years. completed in 2013 and post closure monitoring activities will continue for 30 April 13, 2012. Site closure work was and post a permit to close the small industrial rubble landfill. Site work was completed In September 2013, Osage also received years. closure monitoring will continue for 30 facility value of the estimated future cost to reclaim the land. reclamation liability is recorded at the present future cost to reclaim the land. recorded at the present value of the estimated As a result of the insurance recovery sites in Nebraska and Iowa which were previously used to convert coal to natural gas. sites in Nebraska and Iowa which were previously used to convert coal to natural T The EP which will be used to help of In March 201 do not believe that any substances from our solid waste disposal activities will pollute under do not believe that any substances from of other responsible parties. further investigations, actions of environmental agencies or the financial viability to remediate the Blair and Plattsmouth sites in operator of the Nebraska MGPs. Under this agreement, Nebraska Gas agreed in Nebraska's Nebraska. Subsequent to this transaction, Nebraska Gas enrolled Blair and Plattsmouth and other liabilities on our Consolidated Balance Sheets. As of Dec. 31, 2013, our estimated liabilities for all of the MGP assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages. over time. In this event, we could incur material costs to mitigate any resulting assurance that pollution will not occur is a potential for additional minimal remediation Program. Site remediation was completed in September 2012, however there sites will be required to monitor groundwater work at Plattsmouth where monitoring is required until 2015. Both Nebraska quality for a minimum two year period. million 180 |10K FORM 10K indemnification forreclamation andsuretybonds. our subsidiaries. W (19) disclosures includedinNote to bindingarbitration. the disputedclaims.FollowingahearinginJuly2013, court enteredanorderremandingallbutoneofthedisputedclaims the ColoradoDistrictCourtforCityandCountyofDenver Purchase After thesaleofEnserco,ourEner Sale ofEnsercoEner material adverseef information currentlyavailable,however W because damageclaimsarecurrentlyincompleteorundocumented.Furthermaybepresentedbytheseandother parties. reasonably possible. investigation. Giventheuncertaintyoflitigation,however ongoing. compensatory damages,thelawsuitseeksrecoveryofpunitivedamages.Ourinvestigationcauseandorigin thefireis operations, anddiminishedvalueofrealestate,foracurrenttotalamount rehabilitation costs,damagetofencingandotherpersonalproperty additional landownerandfromtheStateof and trespass. claims fordamagesagainstBlackHillsPowerbaseduponallegationsofnegligence,negligenceperse,commonlaw nuisance, April 16,2013,thirty-fiveprivatepartiesfiledsuitintheUnitedStatesDistrictCourtforof that thefirewascausedbyfailureofatransmissionstructureowned,operatedandmaintainedBlackHillsPower On June29,2012,aforestandgrasslandfireoccurredinthewesternBlackHillsof Oil CreekFire insurance policiesthatmayprovidecoverageagainstcertainclaimsundertheseindemnities. indemnifications. Incertaincases,wehaverecourseagainstthirdpartieswithrespecttotheseindemnities.Further contain anylimitsonourliabilityandtherefore,itisnotpossibletoestimatepotentialunderthese directors, of information technologyagreements,purchaseandsaleagreementsleasecontracts. In thenormalcourseofbusiness,weenterintoagreementsthatincludeindemnificationinfavorthirdparties,suchas regulations, willnotexceedtheamountsreflectedinconsolidatedfinancialstatements. alleged liabilitiesfromvariouslegalproceedings,claimsandothermattersdiscussed,tocomplywithapplicablelaws the probableandestimablecontingencies.However under lawsandregulations. In thenormalcourseofbusiness,wearesubjecttovariouslawsuits,actions,proceedings,claimsandothermattersasserted Legal Pr recovery oragreementswithotherpotentiallyresponsiblepartieswhenandwherepermitted. in certainjurisdictions. Prior toBlackHillsCorporation'sownership, e haveenteredintovariousagreementsprovidingfinancial orperformanceassurancetothirdpartiesonbehalfofcertain e cannotpredicttheoutcomeofourinvestigation,viabilityallegedclaimsorlitigation.Base d upon GUARANTEES oceedings W Agreement, thebuyerrequestedcertainpurchasepriceadjustments, whichwedisputed. e havedeniedandwillvigorouslydefendallclaimsarisingoutofthefire,pendingcompletionour ficers andemployeesinaccordancewithourarticlesofincorporation,asamended.Certainagreementsdonot Although notcurrentlyincludedinthelawsuit,BlackHillsPoweralsoreceivedwrittendamageclaimsfroman The agreementsincludeguarantees ofdebtobligations,contractualperformanceobligations and fect uponourfinancialcondition,resultsofoperationsorcashflows. W gy Inc. Arbitration wascompletedterminatingthepurchaseprice dispute inJanuary2014.Seeadditional e cannotreasonablyestimatetheamountofapotentiallossbecauseourinvestigationisongoing,and W e anticipaterecoveryofthesecurrentandfuturecostswouldbeallowed. W 21 oftheseNotestoConsolidatedFinancialStatements. e believetheamountsprovidedinconsolidatedfinancialstatementsareadequatelightof gy Marketingsegment,onFeb.29,2012,andpursuanttothe provisionsoftheStock , managementdoesnotexpecttheclaims,ifdeterminedadverselytous,havea W yoming. Aquila receivedrateordersthatenabledrecoveryofenvironmentalcleanupcosts
, therecanbenoassurancethattheactualamountsrequiredtosatisfy Altogether theclaimsseekrecoveryforfiresuppression,reclamationand , alossrelatedtothefire,litigationandclaims,is 180 , Colo.,seekinganordercompellingbindingarbitrationon allof , allegedinjurytotimber $15 million.Inadditiontoclaimsforthese W yoming. W e havealsoagreedtoindemnifyour , grassorhay A fireinvestigatorconcluded The buyerfiledapetitionin Additionally W , livestockandrelated yoming, asserting , wemaypursue , wemaintain . On FORM 10K 10K | 181 43 673 8,317 44,384 38,638 92,055 2011 , evolving Ongoing Ongoing $ $ Expiration 115 158 2,437 33,052 73,877 109,639 2012 The guarantee is a 70,000 64,449 134,449 $ $ 10 states and holds leases on 234 143 6,022 12,817 48,641 67,857 Dec. 31, 2013 2013 . Maximum Exposure at Exposure Maximum $ $ $ $ gy Marketing Corp, Northern Natural Gas gy Marketing Corp, Northern 1, and a reconciliation of the changes between The guarantees were entered into in the normal The guarantees were entered Canada Ener 181 (2) (1) 1,224 gross developed oil and gas wells in Dec. 31, 2013, 2012 and 201 gy Company and/or BP Ener s quantities of proved developed and undeveloped oil and natural gas reserves, s quantities of proved developed and undeveloped oil and natural gas reserves, VES (Unaudited) These commodity transactions secure natural gas supply for our regulated gas utilities. secure natural gas supply for our These commodity transactions o the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included by the surety bonds, such liabilities are included are incurred as a result of activities covered o the extent liabilities T 235,517 net acres. AND GAS RESER ed
These estimates are based on reserve reports by CG&A. Such reserve estimates are inherently imprecise and may These estimates are based on reserve reports by CG&A. Such reserve estimates OIL e have guaranteed some of the obligations of Black Hills Utility Holdings for payment obligations arising from commodity-related Holdings for payment obligations arising from of the obligations of Black Hills Utility e have guaranteed some e have guarantees in place for reclamation and surety bonds for our subsidiaries. for reclamation and surety bonds for our e have guarantees in place has operating and non-operating interests in has operating and non-operating interests W transactions with BP physical and financial Company and PSCo. in our Consolidated Balance Sheets. in our Consolidated Balance continuing guarantee that may be terminated upon 30 days written notice to the counterparty that may be terminated upon 30 days written continuing guarantee W course of business. Total costs incurred e had the following guarantees in place as of (in thousands): place as of in guarantees the following e had Proved Unproved Acquisition of properties: Exploration costs Development costs Asset retirement obligations incurred Nature of Guarantee Nature of bonds reclamation/surety for subsidiary Indemnification Guarantees of payment obligations arising from commodity-related physical and commodity-related arising from of payment obligations Guarantees Hills Utility Holdings of Black financial transactions BHEP (20) The following table summarizes BHEP’ ______(1) approximately Costs Incurr years in oil and gas property acquisition, exploration and development during the Following is a summary of costs incurred ended Dec. 31 (in thousands): Reserves estimated using SEC-defined product prices, as of these dates. varying economic conditions. production history and continual reassessment of the viability of production under be subject to revisions as a result of numerous factors including, but not limited to, additional development activity be subject to revisions as a result of numerous factors including, but not limited W (2) 182 |10K FORM 10K changes inPUDlocationsduringtheyear Companies arerequiredtoincludeanarrativedisclosureof thetotalquantityofPUDlocationsatyearend,anymaterial categorized asproved.In2013,wehad SEC regulationsrequirethatprovedundevelopedlocations meetthetestofbeingdevelopedwithinfiveyears performance in positive revisiontoyear oil andnaturalgaspricesreceivedatthewellhead( In 2013,wehadpositiverevisions( success inotherfuturedrilling. made todevelopfutureoilopportunities.Futurecapitalspendingratesareanticipatedbedependentonproductprices and Shale) andfurtherdevelopmentofourholdingsinthe Basin ofOklahoma( Basin (BakkenShale)accountedfor Piceance, Reserve additionstotaled (b) (a) ______Well-head reserveprices NYMEX prices included inabove Proved undevelopedreservesattheendofyear above Proved developedreservesatendofyearincluded Proved developedandundevelopedreserves: Balance atendofyear Balance atbeginningofyear Additions -acquisitions(sales) Revisions topreviousestimates Additions -extensionsanddiscoveries Production • • Reflects thesaleofmajority Production forreservecalculationsdoesnotincludevolumesnaturalgasliquids(NGLs). Minor differ W approximately Six grossPUDlocationsremain undrilled asofDec.31,2013. locations weredrilledandwe invested In 2012,wehad1 W illiston Basin. illiston andPowderRiverBasins.DrillinginPiceanceBasin(MancosShale)accountedfor (a) one W ences inamountsmayr 0.2 Bcfe).Capitalspendingin illiston BasingrossPUDlocationresultedinaslightnegative revisionof -end 2012provedreserves.Increasedoperatingcostsinthe SanJuanBasinandreducedexpectationsof $2.1 million 12.7 Bcfe,replacing 1 grossPUDlocationsfor1.4 Bcfe;allwereinthe (b) 2.5 Bcfe)topreviousreserveestimates.Mostofthepositiverevisionswereduehigher offutureinvestmentwhendrilled willdevelopapproximately 2.1 Bcfe,andrecompletionsinthePowderRiverBasin( W no PUDlocationsthatwererequiredtobedroppedbecauseof thefiveyearrule. illiston Basinassetsduring2012. , andinvestmentprogressmadeinconvertingthePUD locationsduringtheyear esult inthefollowingtablesr 90 percentofproduction. $3.6 million 5.0 Bcfe). 2013 wasprimarilyforevaluationdrillinginthePiceanceBasin(Mancos W $ $ illiston BakkenBasins. Oil anddeveloped 89.79 96.94 3,689 3,921 4,116 Additionally 182 (336 (208 232 379 (30 2013 ) ) ) $ $ Gas The remaining2012PUDlocations require 60,224 63,190 10,456 55,985 (6,984 Additions mainlyresultedfromdrillinginthe elating tooilandgasr 2,966 3,779 , betterwellperformanceresultedin (in MbblsofoilandMMcfgas) 3.45 3.67 (46 0.6 Bcfe. W ) ) Additionally illiston Basin.In2013, $ $ Oil (2,025 3,929 4,116 6,223 85.31 94.71 (560 187 449 29 2012 ) ) $ $ , exploratoryinvestmentswere 0.2 Bcfe)andinthe (31,061 eserves duetor Gas 2.1 Bcfe 55,708 55,985 95,904 (8,686 (3,070 2,898 2.24 2.76 0.5 Bcfereservesinthe 279 ) ) ) five ofthosePUD 10.2 Bcfe, $ $ Oil 4,830 6,223 5,940 1,393 88.49 96.19 (452 (108 0.4 Bcfe 927 ounding. (84 2011 Anadarko ) ) ) W $ $ illiston (20,690 Gas 71,867 95,904 95,456 24,037 29,664 (8,526 3.59 4.12 — . ) ) FORM 10K ) 10K | 183 28,656 674,494 703,150 341,977 (361,173 2011 $ $ ) 2.1 6.5 6.4 0.9 -end proved -end proved 13.8 15.9 59,526 662,444 721,970 187,193 (534,777 illiston Basin. illiston Basin. well in the San Juan Basin Juan Basin in the San well 2012 W one Future $ $ (in millions) ) Development Costs $ $ 6 1 1 62,553 15 17 23 725,345 787,898 232,635 (555,263 2013 $ $ Locations Gross PUD gross PUD location in the one gross PUD illiston Basin Bakken drilling, drilling, Basin Bakken illiston 0.5 1.2 2.1 0.6 3.9 4.4 W 183 (in Bcfe) Proved Reserves illiston Basin assets during 2012 recorded under the full-cost method of accounting. W were: Dec. 31, 2013 fset well performance resulted in dropping resulted fset well performance 2013 Add Total Williston Basin Williston Basin Piceance Basin San Juan Basin Added: Existing: Total Proved Undeveloped (a) gross PUD locations for future for PUD locations 15 gross we added In 2013, Piceance Mancos Shale well PUD location. well PUD Shale Mancos Piceance and one of Analysis of our year costs in and future development undeveloped reserve of locations, proved The number reserves as of undeveloped of our PUD locations have been reflected in our reserves for five or more years. Consistent with the SEC None of our PUD locations have been reflected monitored and reported each year until they are drilled or revised. guidance, these PUD locations will be Reflects the sale of the majority of the • • • • Gross capitalized costs Net capitalized costs Proved oil and gas properties amortization and valuation Accumulated depreciation, depletion and allowances Unproved oil and gas properties ______(a) Following is information concerning capitalized costs for the years ended Dec. 31 (in thousands): Following is information concerning capitalized Capitalized Costs 184 |10K FORM 10K year inwhich gas reservesfortheyearsendedDec.31(inthousands): Following isasummaryofthestandardizedmeasurediscounted futurenetcashflowsandchangesrelatingtoprovedoil Standardized Measur The listed belowtobeaddedthecostpoolinnextyear timing oftheultimateevaluationanddispositionpropertieshasnotbeendetermined. included intheamortizationbaseoffull-costpool. million acquisitions andthroughdirectpurchasesofleasehold. various existingwork-in-progressprojectsaswellleaseholdacquiredthroughsignificantnaturalgasandoilproperty Unproved propertiesnotsubjecttoamortizationat Following isasummaryofresultsoperationsforproducingactivitiestheyearsendedDec.31(inthousands): Results ofOperations Standardized measureofdiscounted futurenetcashflows 10 percentannualdiscountfor estimatedtimingofcashflows Future netcashflows Future incometaxexpense Future developmentcosts,includingpluggingandabandonment Future productioncosts Future cashinflows Total Capitalized interest Exploration cost Leasehold acquisitioncost administrative costsandinterestcosts) Results ofoperationsfromproducingactivities(excludinggeneraland Income taxbenefit(expense) Impairment oflong-livedassets Depreciation, depletionandamortizationvaluationprovisions Gain onsaleofassets Production costs Revenue Results ofoperationsfromproducingactivitiesbeforetax Total costs table ofinterestduring below the associated sets forth e ofDiscountedFutur 2013, 2012and201 the costs wereincurred(inthousands): cost of $ $ unproved 2013 1, respectively e NetCashFlows properties 13,957 10,930 2,279 748 Dec. 31,2013,2012and201 W W $ $ . e willcontinuetoevaluateourunevaluatedproperties;however e capitalizedapproximately excluded , onsignificantinvestmentsinunprovedpropertiesthatwerenotyet 184 2012 36,049 35,689 from 360 — the $ $ $ $ $ $ amortization 1 consistedmainlyofexplorationcoston 2011 2013 2013 (107,375 (213,578 266,800 159,425 602,501 (81,566 (40,557 20,611 20,140 54,884 14,133 40,751 (4,876 $1.1 million 9,257 2,856 2,219 637 — — — base W ) ) ) ) ) $ $ $ $ e expecttheexplorationcost $ $ as of , $0.7million 2012 2012 Prior Dec. (101,632 (186,695 237,735 136,103 502,769 (69,877 (29,129 26,868 37,323 23,483 13,445 79,072 20,527 58,545 20,621 17,444 (8,462 (7,082 3,177 31, — 2013 ) ) ) ) ) ) $ $ $ $ $ $ and$0.9 and 2011 2011 Total (197,215 (157,922 (280,910 400,572 203,357 931,637 notes (92,233 73,483 10,930 57,631 34,415 23,820 14,131 79,808 21,573 58,235 , the (7,442 4,922 — — the ) ) ) ) ) FORM 10K ) ) ) ) 10K | 185 — (1,013 57,087 31,179 43,809 18,940 19,655 (52,914 (58,211 (23,283 203,357 168,108 2011 . illiston Basin in $ $ As a result of the W ) ) ) ) — , this methodology does 19,870 43,854 21,931 25,509 36,578 (37,175 (48,905 (42,639 (86,277 136,103 203,357 2012 ypically T $ $ ) ) ) ) — (869 A. See Note 18 for further information. 3,554 (3,892 15,126 29,574 12,851 15,126 (35,932 (12,216 159,425 136,103 2013 TIONS Three Forks shale assets in the $ $ ownership interest in the Busch Ranch 50 percent ownership interest in the Busch Ranch 185 iming of future development investments are reviewed each year and iming of future development investments T AND DISCONTINUED OPERA illiston Basin asset sale significantly altered the relationship and accordingly we illiston Basin asset sale significantly altered the relationship and accordingly we gy produced by the wind farm through a REP gy produced by the wind farm through These production profile modifications are based on incorporation of the most recent These production profile modifications W The July 1, 2012, was used to determine the sales price. ASSETS . Assets with the remainder of the proceeds recorded as a reduction in the full cost pool. with the remainder of the proceeds recorded as a reduction in the full cost pool. . Colorado Electric retains the remaining undivided interest and is the operator of this jointly . Colorado Electric retains the remaining TING Assets s interest in the ener fective date of illiston Basin assets in 2012. ’ OPERA Assets W $29 million (a) $25 million An ef . Commercial operation of the newly constructed wind farm commenced on Oct. 16, 2012. Colorado Electric will . Commercial operation of the newly constructed SALE OF Reflects sale of ind project for Standardized measure - end of year Standardized measure Standardized measure - beginning of year measure - beginning Standardized production costs gas produced, net of transfers of oil and Sales and costs in prices and production Net changes costs and improved recovery, less related Extensions, discoveries costs Changes in future development incurred during the period Development costs quantity estimates Revisions of previous Accretion of discount taxes Net change in income Purchases of reserves Sales of reserves not allow for gain or loss on sale and proceeds from sale are credited against the full cost pool. Gain or loss recognition is not allow for gain or loss on sale and proceeds from sale are credited against the capitalized costs and proved reserves of oil allowed when such adjustments would significantly alter the relationship between and gas attributable to a cost center recorded a gain of ______North Dakota. gas activities. Our Oil and Gas segment follows the full-cost method of accounting for oil and and amortization rate declined during reduction in the full cost pool from the sale of these assets, the depreciation, depletion, 2013. , Colorado Electric completed the sale of an undivided On Sept. 18, 2012, Colorado Electric completed the sale Partial Sale of Oil and Gas Partial Sale of Electric Utilities W owned facility purchase our partner On Sept. 27, 2012, our Oil and Gas segment sold a majority of its Bakken and Sale of Operating Changes in the standardized measure from “revisions of previous quantity estimates” are driven by reserve revisions, “revisions of previous quantity estimates” are driven by reserve revisions, Changes in the standardized measure from timing of future development. For all years presented, we had minimal net reserve modifications of production profiles and each Production forecast modifications are generally made at the well level revisions to prior estimates due to performance. year through the reserve review process. technical studies. production information and applicable (a) are often modified in response to current market conditions for items such as permitting, and service availability are often modified in response to current (21) The following are the principal sources of change in the standardized measure of discounted future net cash flows during the during cash flows future net of discounted measure standardized in the of change sources are the principal The following thousands): 31 (in ended Dec. years 186 |10K FORM 10K discontinued operationsinaccordance withGAAP T (a) ______accompanying ConsolidatedStatementsofIncomewereasfollows(inthousands): Operating resultsoftheEner settlement ofunresolvedpurchasepriceadjustments. million an additional million claims weresubstantiallyresolvedinourfavorthroughabindingarbitrationdecisiondatedJan.17,2014. The buyerassertedcertainpurchasepriceadjustments,somethatweaccepted,andseveraldisputed. the buyerand approximately completed throughastockpurchaseagreementandcertainotherancillaryagreements.Netcashproceedsatdateofsale were On Feb.29,2012,wesoldtheoutstandingstockofourEner Ener reclassification onaconsistentbasis. “Liabilities ofdiscontinuedoperations.”Forcomparativepurposes,allpriorperiodspresentedhavebeenrestatedtoreflectthe classified andreflectedontheaccompanyingConsolidatedBalanceSheetsas“Assetsofdiscontinuedoperations” taxes intheaccompanyingConsolidatedStatementsofIncome. Results ofoperationsfordiscontinuedhavebeenclassifiedasIncomefromoperations,netincome Discontinued Operations Net cashproceeds,subsequenttothetrue-upofallpost-closingadjustments,wereasfollows(inthousands): Income (loss)fromdiscontinuedoperations,netoftax Income tax(expense)benefit Pre-tax gain(loss)onsale Pre-tax income(loss)fromdiscontinuedoperations Revenue For theYearsEndedDec.31, otal indirectcorporatecostsand inter 2012 includestransactionrelatedcosts,netoftax, gy MarketingSegment and$7.0million in2012,relativetopurchasepriceadjustmentsweacceptedthroughapartialsettlementagreementwiththebuyer $1.1 million $58 millioncashretainedfromEnsercobeforeclosing. $165 million * ______Cash proceedsreceivedondateofsale Net cashproceeds Estimated paymentforcontractualobligationrelatedto“back-in”fee* Transaction adviserfees Post closeadjustments Less: participation agreementwiththepropertyoperator Required payment,triggeredbythesaleofproperty forthetwelvemonthsended in2013relativetotheclaimsassignedarbitration.Lossfromdiscontinuedoperationswas , subjecttofinalpost-closingadjustments. gy MarketingsegmentincludedinIncome(loss)fromdiscontinuedoperations,netoftaxonthe -segment interestexpensespreviously allocatedtoEnsercowerenotreclassified andinsteadhavebeenreclassified toourCorporatesegment. $2.5 millionfortheyearended Dec. 31,2013and2012,respectively (a) gy Marketingsegment,EnsercoEner 186 Assets andliabilitiesofthediscontinuedoperationshavebeen . , arisingfromacontractualobligationcontainedintheoriginal Those proceedsrepresented $ $ Dec. 31,2012. 2013 (1,391 (884 507 — — . Resultsfor2013includethe ) ) $ $ gy Inc. $ $ 2012 $108 million (6,977 (4,184 (6,061 243,314 227,860 3,268 (16,847 (604 The transactionwas (1,400 2,793 W e expensed The disputed ) ) ) ) $ $ ) ) receivedfrom 2011 $0.9 41,101 14,838 $1.4 (5,473 9,365 , and — ) FORM 10K ) ) ) 10K | 187 - 0.43 0.41 0.43 0.41 (884 (0.02 (0.02 0.380 54.83 47.00 71,103 19,007 18,123 355,448 Fourth f of Quarter $ $ $ $ $ $ $ $ $ $ $ $ — — — $0.5 million after 0.52 0.52 0.52 0.52 0.380 55.09 46.62 55,566 23,124 23,124 259,907 , and Third Quarter $ $ $ $ $ $ $ $ $ $ $ $ — — — -tax expense relating to the 0.69 0.69 0.69 0.69 0.380 50.53 43.19 49,037 30,518 30,518 279,826 after Second Quarter s project financing and write-of $ $ $ $ $ $ $ $ $ $ $ $ and common stock prices) and common stock f of deferred financing costs relating to the — — — yoming’ 0.98 0.98 0.97 0.97 , $12 million, $2.0 million $6.6 million 0.380 44.32 36.89 W 79,846 43,197 43,197 380,671 First Quarter (in thousands, except per share amounts, dividends except per share (in thousands, $ $ $ $ $ $ $ $ $ $ $ $ $4.8 million 187 . The following tables set forth select unaudited historical operating results and operating results select unaudited historical tables set forth The following (Unaudited) (a) (b) -tax for a make-whole premium and write-of A T after (a) (b) DA notes and interest expense on new debt, and a notes and interest expense on new debt, and 2012. 2013 and ORICAL $7.6 million $250 million HIST Y
TERL QUAR Includes unrealized mark-to-market gain (loss) for interest rate swaps of Includes unrealized mark-to-market gain (loss) respectively tax in the first, second, third and fourth quarters, Fourth quarter 2013 includes early redemption of our with the prepayment of Black Hills settlement of interest rate swaps in conjunction deferred financing costs. Common stock prices - High Common stock prices - Low 2013 Revenue Operating income continuing operations Income (loss) from discontinued operations Income (loss) from for common stock Net income (loss) available for continuing operations - Basic Income (loss) per share operations - Basic Income (loss) per share for discontinued Income (loss) per share - Basic operations - Diluted Income (loss) per share for continuing operations - Diluted Income (loss) per share for discontinued Income (loss) per share - Diluted Dividends paid per share (a) (b) ______(22) The Company operates on a calendar year basis. operates on a calendar The Company for each quarter of market data 188 |10K FORM 10K (d) (c) (b) (a) ______Dividends paidpershare Income (loss)pershare-Diluted Income (loss)persharefordiscontinuedoperations-Diluted Income (loss)pershareforcontinuingoperations-Diluted Income (loss)pershare-Basic Income (loss)persharefordiscontinuedoperations-Basic Income (loss)pershareforcontinuingoperations-Basic Net income(loss)availableforcommonstock Income (loss)fromdiscontinuedoperations Income (loss)fromcontinuingoperations Operating income Revenue 2012 Common stockprices-Low Common stockprices-High Fourth quarterincludesa on saleofthe Second quarterincludesanafter tax inthefirst,second,thirdandfourthquarters,respectively Includes unrealizedmark-to-marketgain(loss)forinterestrateswapsof sale ofthe Second quarterincludesapre-taxceilingtestimpairmentlossof W illiston Basinassetsof W (a) illiston Basinassetsof $4.6 millionafter -tax ceilingtestimpairmentlossof $27 million $18 million (b) (c)(d) -tax make-wholeprovisionfortheearlyredemptionofour (b) (c)(d) and and $1.8 million,respectively $1.2 million,respectively . 188 $27 million $17 million $7.8 million andthethirdfourthquartersincludeapre-taxgainon $ $ $ $ $ $ $ $ $ $ $ $ . (in thousands,exceptpershareamounts,dividends andthethirdfourthquartersincludeanafter Quarter First . 365,851 29,787 35,271 70,048 (5,484 32.18 35.82 0.370 (0.12 (0.13 , $(10)million$0.4 0.68 0.80 0.68 0.81 ) ) ) and commonstockprices) $ $ $ $ $ $ $ $ $ $ $ $ Quarter Second 242,363 (13,483 (12,323 20,591 (1,160 31.32 34.31 0.370 (0.31 (0.03 (0.28 (0.31 (0.03 (0.28 $225 million ) ) ) ) ) ) ) ) ) $ $ $ $ $ $ $ $ $ $ $ $ Quarter Third 246,808 , and$3.1million 34,457 34,623 77,810 30.29 36.28 0.370
(166 notes. 0.78 0.78 0.79 0.79 — — ) $ $ $ $ $ $ $ $ $ $ $ $ Quarter Fourth 318,862 -tax gain 30,767 30,934 75,262 33.51 37.00 0.370 after (167 0.70 0.70 0.70 0.70 — — - ) FORM 10K 10K | 189 , Aquila ficer — Retail April 2003. AND AND ficer and a ficer of two echnology from June T Annual Report on Form Annual Report on Form Aquila for 28 years. fective. . Act)) as of Dec. 31, 2013 ACCOUNTING ACCOUNTING 14 of this 1 Annual Meeting of Shareholders, ficer since July 2008. He was an ficer since the closing of the yoming from 2002 until joining the ANTS ON ANTS 2014 TE GOVERNANCE W ice President of Information fectiveness of our disclosure controls and procedures fectiveness of our disclosure Act of 1934 (Exchange Act of 1934 (Exchange V ge engineering and construction company involved in s ice President and Chief Financial Of ACCOUNT V Aquila’ WITH WITH AND CORPORA 189 ice President — Fuel Resources from January 1997 to ice President — Fuel Resources from January . V , he was ficer evaluated the ef ice President and Chief Financial Of April 2005 and has been President and Chief Executive Of April 2005 and has been President and ice President — Chief Information Of V V fect our internal control over financial reporting. fect our internal control over financial TION . es AND DISAGREEMENTS DISAGREEMENTS AND AND PROCEDURES DISCLOSURE ashington Group, International, Inc., a lar ocedur W ORS, EXECUTIVE OFFICERS ouche LLP , there have been no changes in our internal control over financial reporting that have materially changes in our internal control over financial , there have been no T echnology from February 2002 until January 2004. He was employed with April 2003 to January 2004 and ficer and Chief Financial Of ficer and Chief Financial T Financial Reporting , developer and consultant with companies in Colorado and ols and Pr FINANCIAL CONTROLS DIRECT CHANGES IN IN CHANGES OTHER INFORMA , age 51, was elected Chairman in ol over s Report on Internal Control over Financial Reporting is presented on Page Control over Financial Reporting is presented s Report on Internal e Contr III A. Buchholz, age 52, has been our Senior T . Emery has 24 years of experience with the Company . Emery has 24 years of experience with fected or are reasonably likely to materially af fected or are reasonably likely to materially ransaction in July 2008. Prior to joining the Company AR 10-K. Management’ David R. Emery ITEM 9A. ITEM 9A. P Executive Officers None. Disclosur controls and procedures are ef they have concluded that our disclosure Based on their evaluation, Internal Contr During our fourth quarter af None ITEM 10. 407 respect to directors and information required by Items 401, 405, 406, 407(c)(3), Information required under this item with is set forth in the Proxy Statement for our (d)(4) and 407(d)(5) of Regulation S-K, which is incorporated herein by reference. January 2004. Prior to that, he was our President and Chief Operating Of member of the Board of Directors since Business Segment from Mr Scott T ITEM 9. ITEM Our Chief Executive Of Our Chief Executive ITEM 9B. (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange 13a-15(e) and 15d-15(e) of the Securities (as defined in Rules 2004 until June 2005, and General Manager 2005 until July 2008, Six Sigma Deployment Leader/Black Belt from January Corporate Information independent investor publicly-traded companies: builder of factory-built housing. Before his CFO power plant construction and mining operations, and Champion Enterprises, a Inc., and eight years in public roles, he spent 15 years in various senior financial positions with Honeywell International, accounting at Deloitte & Anthony S. Cleberg, age 61, has been Executive Company in 2008. Prior to his consulting role, he was the Executive 190 |10K FORM 10K (2) (1) ______EQUITY for our2014 Information regardingthesecurityownershipofcertainbeneficialownersandmanagementissetforthinProxy Statement ITEM 12. incorporated hereinbyreference. Information requiredunderthisitemissetforthintheProxyStatementforour ITEM 1 leadership roles. Reebok International,LtdfromNovember2003untilJanuary2006.Hehasover33yearsofserviceinkeyhumanresources for DevonEner resources consultingfirm,fromOctober2006untilDecember2008,Senior as ourInterimHumanResourcesExecutivesinceJune2008.HewasapartnerwithStrategic Robert Counsel andCorporateSecretaryfrom2001to2004.Mr 2008. HeservedasourSenior Steven J.Helmers, served asour the Linden R.Evans, include the1999StockOptionPlan,2001OmnibusIncentivePlanand2005Plan. The followingtableincludesinformationasof approved bysecurityholders Equity compensationplansnot security holders Equity compensationplansapprovedby Total
V other stockbasedawards. options, stockappreciationrights, restrictedstock,stockunits,performanceshares, units,cash-basedawardsand Shares availableforissuanceare fromthe2005OmnibusIncentivePlan. above tablebecausetheyhavealreadybeenissued. stock units.Inaddition,262,741sharesofunvestedrestricted wereoutstandingasof common stockunits. Includes 227,844fullvalueawardsoutstandingasof ice PresidentandGeneralManagerofourformercommunicationsubsidiaryfromDecember2003toOctober2004, A. Myers,age56,hasbeenourSenior 1. COMPENSA Annual MeetingofShareholders,whichisincorporatedhereinbyreference. Associate CounselfromMay2001toDecember2003.Mr Plan category gy fromMarch2006untilSeptember2006,andSenior RELA SECURITY EXECUTIVE COMPENSA age51,hasbeenPresidentandChiefOperatingOf age 57,hasbeenourSenior The weightedaverageexercisepricedoesnotincludetherestricted stockunits,performancesharesorcommon TION PLANINFORMA TED ST V OWNERSHIP ice President,GeneralCounselsinceJanuary2004andourSenior OCKHOLDER MA Number ofsecuritiestobe Equity CompensationPlanInformation issued uponexerciseof outstanding options, warrants andrights OF Dec. 31,2013withrespecttoourequitycompensationplans. V TION V ice President—ChiefHumanResourceOf ice President,GeneralCounselandChiefComplianceOf CER TION Dec. 31,2013,comprisedofrestrictedstockunits,performancesharesandDirector (a) TTERS . Helmershas13yearsofexperiencewiththeCompany T 288,311 288,311 AIN BENEFICIAL 190 — (1) ficer —UtilitiessinceOctober2004.Mr The 2005OmnibusIncentivePlan permitsthegrantofstock V Weighted-average exercise . Evanshas12yearsofexperiencewiththeCompany ice PresidentandChiefHumanResourceOf options, warrantsand price ofoutstanding $ $ $ V ice President—ChiefHumanResourceOf OWNERS 2014 rights (b) Annual MeetingofShareholders,whichis Dec. 31,2013,whicharenotincludedinthe 33.25 33.25 AND MANAGEMENT — ficer sinceJanuary2009andserved T alent Solutions,ahuman (1) V equity compensationplans ice President,General reflected incolumn(a)) remaining availablefor future issuanceunder Number ofsecurities (excluding securities ficer sinceJanuary These plans . Evansservedas (c) . 768,953 768,953
AND ficer at — ficer (2) . FORM 10K 10K | 191 Annual Meeting to OR 2014 AND DIRECT AND TRANSACTIONS, TRANSACTIONS, VICES TED TED 191 SCHEDULES AND SER AND RELA AND TEMENT A ST TIONSHIPS TIONSHIPS ACCOUNTING FEES ACCOUNTING
AL AIN RELA AIN Annual Meeting of Shareholders, which is incorporated herein by reference. which is incorporated of Shareholders, Annual Meeting T 2014 CER PRINCIP INDEPENDENCE EXHIBITS, FINANCIAL Consolidated Financial Statements Consolidated Financial item are included in Item 8 of Part II Financial statements required under this Schedules of the Registrant Schedule I — Condensed Financial Information and Qualifying Accounts for the years ended Dec. 31, 2013, 2012 and Schedule II — Consolidated Valuation 2011 because of the absence of the conditions under which they are All other schedules have been omitted is included in our consolidated financial statements and notes required or because the required information thereto. Exhibits 1. 2. 3. IV T AR (a) ITEM 13. ITEM ITEM 14. ITEM 14. P Information regarding certain relationships and related transactions and director independence is set forth in the Proxy is set forth in and director independence transactions relationships and related regarding certain Information for our Statement our is set forth in the Proxy Statement for principal accounting fees and services Information regarding is incorporated herein by reference. Shareholders, which ITEM 15. 192 |10K FORM 10K Comprehensive income(loss) Other comprehensiveincome(loss),netoftax: Net income(loss)availableforcommonstock Years ended(inthousands) Net income(loss)availableforcommonstock Income taxbenefit(expense) Income (loss)beforeincometaxes Other income(expense): Operating expenses Revenue Other income(expense),net Interest income Unrealized gain(loss)oninterestrateswaps,net Interest expense Equity income(loss)inearningsofsubsidiaries respectively) in netincome(loss)(netoftax$(2,016),$534and$(709), Reclassification adjustmentofcashflowhedgessettledand included (net oftax$(2,445),$887and$1,708,respectively) Fair valueadjustmentonderivativesdesignatedascashflow hedges cost (netoftax$88,$0and$0) Reclassification adjustmentofbenefitplanliability-prior service (net oftax$(971),$0and$0) Reclassification adjustmentofbenefitplanliability-netgain (loss) $185, $86and$176,respectively) Benefit planliabilityadjustments-priorservice(costs)(net oftax $(3,813), $296and$4,135,respectively) Benefit planliabilityadjustments-netgain(loss)(netoftax Operating income(loss) (loss) ofconsolidatedsubsidiaries Other comprehensiveincome (loss),netoftax,includingearnings Total otherincome(expense) The accompanying notestocondensedfinancial statements areanintegralpartof thesecondensedfinancialstatements. The accompanyingnotestocondensedfinancialstatementsareanintegralpartofthesestatements. CONDENSED ST BLACK HILLSCORPORA BLACK HILLSCORPORA CONDENSED ST A TEMENTS OF SCHEDULE I A TEMENTS OF COMPREHENSIVEINCOME(LOSS) 192 TION (P TION (P ARENT ARENT $ $ $ $ Dec. 31,2013 INCOME COMP COMP 2013 133,028 114,962 121,720 123,059 114,962 100,690 18,066 30,169 (6,758 (7,827 (1,339 4,046 4,534 1,820 8,237 1,339 (165 (406 ANY) ANY) — 30 (3 ) ) ) ) ) ) $ $ $ $ Dec. 31,2012 (in thousands) 2012 (19,665 78,918 81,528 (2,610 (1,268 74,946 75,777 81,528 93,479 6,582 1,882 (643 (157 (542 (831 831 — — 49 — 32 ) ) ) ) ) ) ) $ $ $ $ Dec. 31,2011 2011 (15,229 (42,010 40,433 49,730 20,630 29,100 29,872 49,730 87,150 (9,297 (2,831 (7,609 1,468 (325 (772 772 (42 — — — 3 ) ) ) ) ) ) ) ) FORM 10K 193 (This pageleft mostly blankintentionally.) 194 |10K FORM 10K Current assets: At Dec.31, Current liabilities: TOTAL ASSETS Investments insubsidiaries Property andEquipment Long-term debt,netofcurrentmaturities Derivative liabilities,non-current TOTAL LIABILITIESANDSTOCKHOLDERS’EQUITY Total stockholders’equity Note payable—affiliate,non-current Cash andcashequivalents Other assets,non-current Deferred incometaxassets,net,non-current Notes receivable—affiliate,non-current Other currentassets Deferred incometaxassets,net,current Income taxreceivable,net Notes receivable—affiliates,current Accounts receivable—affiliates,current Accounts payable-affiliate,current Deferred incometaxes Derivative liabilities,current Other currentliabilities Current maturitiesoflong-termdebt Notes payable—affiliate,current Notes payable Total long-termdebt Total otherassets,non-current Total currentassets Total currentliabilities The accompanyingnotestocondensedfinancialstatementsarean integralpartofthesecondensedfinancialstatements. LIABILITIES ANDSTOCKHOLDERS’EQUITY BLACK HILLSCORPORA ASSETS CONDENSED BALANCESHEETS 194 TION (P ARENT COMP ANY) $ $ $ $ 2013 2,421,834 1,237,876 1,000,000 2,421,834 1,307,748 1,000,000 762,214 685,000 415,485 393,586 108,472 67,958 14,530 12,775 82,500 (in thousands) 1,664 9,256 6,259 4,705 1,000 3,474 5,614 9,351 372 — — — — $ $ $ $ 2012 2,172,699 1,194,501 2,172,699 1,232,509 295,508 250,000 681,555 637,586 480,157 100,000 277,000 450,000 450,781 41,494 29,779 91,617 1,266 4,014 1,135 4,887 2,194 5,843 9,252 9,943 1,032 565 781 — FORM 10K ) ) ) ) ) ) ) ) ) 10K | 195 — — — — 219 2,895 3,114 3,550 2,841 5,643 2,599 4,376 (5,348 (1,135 (5,141 32,958 49,730 14,500 42,010 (59,202 (25,302 (87,150 123,041 229,189 (821,300 (258,117 (259,252 1,017,300 2011 $ $ ) ) ) ) ) ) ) ) ) ) ) ) — — — — 450 4,726 3,114 1,266 6,541 8,271 3,909 (2,833 (1,848 (6,764 (7,816 (1,882 (8,116 96,073 96,523 81,528 (80,563 (65,262 (17,808 (93,479 203,753 275,806 (271,753 (225,000 2012 (in thousands) $ $ ) ) ) ) ) ) ) ) ) ) ) ) ) — — ANY) 398 4,356 1,266 1,664 3,099 (1,813 (6,932 (5,124 (7,881 (3,184 20,386 19,622 12,595 10,504 (63,939 (67,587 (30,169 337,650 800,000 119,585 114,962 (532,150 (350,000 (133,685 (138,809 (100,690 2013 COMP $ $ CASH FLOWS CASH ARENT TION (P TION 195 TEMENTS OF TEMENTS A CONDENSED ST CONDENSED BLACK HILLS CORPORA HILLS BLACK Net change in cash and cash equivalents Accounts payable and other current liabilities Accounts receivable and other current assets Equity in earnings of subsidiaries Equity in earnings of Dividend from subsidiaries Stock compensation on interest rate swaps, net Unrealized gain (loss) Deferred income taxes net Other adjustments, Common stock issued Short-term borrowings -- repayments Short-term borrowings -- issuances affiliates Increase (decrease) in notes payable to Long-term debt — issuance Long-term debt — repayment De-designated interest swap settlement Other financing activities Cash and cash equivalents beginning of year Cash and cash equivalents end of year Dividends paid on common stock Decrease (increase) in advances to affiliates Other investing activities Property, plant and equipment additions Other operating activities Net income (loss) available for common stock (loss) available for Net income Adjustments to reconcile income (loss) from continuing operations to income (loss) from continuing operations Adjustments to reconcile operating activities — net cash provided by Net cash provided by (used in) financing activities Net cash provided by (used in) investing activities Net cash provided by (used in) investing Financing activities: Net cash provided by (used in) operating activities Net cash provided by (used in) operating Investing activities: Operating activities: Operating assets and liabilities: Change in certain operating Years ended Dec. 31, Years ended 196 |10K FORM 10K Cash (paid)refundedduringtheperiodfor- Non-cash investingandfinancingactivities- Years ended Supplemental CashFlowInformation by subsidiaries Non-Cash dividends,netofnon-cashcontributions,distributedtoParent Cash dividendspaidtoParentbysubsidiaries Form 10-K. in compliancewithallofthesecovenants.SeeNote various banks.Ourcreditfacilityanddebtsecuritiescontain certainrestrictivefinancialcovenants. Additionally external fundsasdefinedundertheagreements. Utility MoneyPool Black HillsCorporationhasnotesreceivableandpayablewithaf (2) Dividends paidanddistributedtoBlackHillsCorporation(theParent)fromitssubsidiarieswereasfollows(inthousands): related notesincludedinthis Therefore, thesecondensedfinancialstatementsshouldbereadinconjunctionwiththeconsolidated and not reflectalloftheinformationandnotesnormallyincludedwithfinancialstatementspreparedinaccordance GAAP Pursuant torulesandregulationsoftheSEC,unconsolidatedcondensedfinancialstatementsBlackHillsCorporation do (1) Income taxes Interest Non-cash dividend,netofnon-cashcontributions,fromaffiliates Non-cash adjustmenttonotespayableaffiliates Non-cash adjustmenttonotesreceivablefromaffiliates NOTES The accompanyingnotestocondensedfinancialstatementsareanintegralpartofthesestatements. NOTES RECEIV BASIS OF T O BLACKHILLSCORPORA , asofDec.31,2013BlackHillsCorporationhasaRevolvingCreditFacilityand acorporatetermloanwith Agreements. Borrowingsundertheseagreementsbearinterestattheweightedaveragedailycostof PRESENT ABLE Annual ReportonForm10-K. A TION AND NOTESP TION (P A 6 toNotesConsolidatedFinancialStatementsonthis Y ARENT ABLE 196 COMP ANY) CONDENSEDFINANCIAL filiates underUtilityMoneyPool $ $ $ $ $ $ $ Dec. 31,2013 2013 (57,315 (57,315 57,315 (4,510 (6,638 — — ) ) ) ) $ $ $ $ $ $ $ (in thousands) Dec. 31,2012 2012 (277,560 At Dec.31,2013,wewere 237,521 (18,550 237,521 40,039 3,911 Agreements andNon- — ST ) ) Annual Reporton $ $ $ $ $ $ $ Dec. 31,2011 A TEMENTS 2011 (14,667 23,830 14,500 . — — — — ) FORM 10K 10K | 197 — — Dec. 250,000 200,000 100,000 550,000 100,000 450,000 2012 filiate, $ $ — — — s Condensed Balance 525,000 200,000 275,000 2013 1,000,000 1,000,000 filiate, non-current on the $ $ filiate, non-current on the
NA June 19, 2015. In 2012, this term loan was 4.25% 9.00% 1.31% 5.88% — — — — Annual Report on Form 10-K for further e have entered into floating-to-fixed Dec. 31, 2013 Interest Rate at Interest Rate W 275,000 725,000 filiate, non-current on the Parent’ ALUE MEASUREMENTS Due Date $ $ $ $ $ $ V July 15, 2020 May 15, 2014 June 19, 2015 Nov. 30, 2023 Sept. 30, 2013 197 AIR This note was redeemed on Dec. 19, 2013 with proceeds from the issuance of This note was redeemed on Dec. 19, 2013 with AND F See Note 19 of the Notes to Consolidated Financial Statements in this 2014 2015 2016 2017 2018 Thereafter s Condensed Balance Sheets. ACTIVITIES
(a) (b) (c) (e) (f) s Condensed Balance Sheets.
8 and 9 of Notes to Consolidated Financial Statements on this (d) (f) The agreements include guarantees of debt obligations, contractual performance obligations and The agreements include guarantees of debt obligations, contractual performance of this senior unsecured note has been recorded at Black Hills Utility Holdings and is recorded as Notes receivable - of this senior unsecured note has been recorded s Condensed Balance Sheets for 2012 and 2013. s Condensed Balance Sheets for 2012 and 2013. s Condensed Balance Sheets at 2013. GUARANTEES RISK MANAGEMENT LONG-TERM DEBT LONG-TERM filiate, non-current on the Parent’ ariable interest rate. the Senior unsecured notes due 2023. by Colorado Electric and is recorded as Notes receivable - af This senior unsecured note has been recorded Parent’ and replaced with the Long-term term loan due This term loan was repaid on June 21, 2013, is recorded as Notes receivable - af recorded by Black Hills Utility Holdings and Sheets for 2013. segment and is recorded as Notes receivable - af This debt has been recorded at our Power Generation Parent’ V af by Black Hills Utility Holdings and was recorded as Notes receivable - af For 2012, this senior unsecured note was recorded $410 million non-current on the Parent’ e have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of e have entered into various agreements providing financial or performance assurance e engage in activities to manage risks associated with changes in interest rates. e engage in activities to manage risks associated with changes in interest rates. Total long-term debt Net long-term debt Senior unsecured notes due 2023 Senior unsecured notes due 2014 Senior unsecured notes due 2020 Senior unsecured notes Long-term term loan due 2015 Corporate term loan Less current maturities (c) (d) (e) (f) Certain debt instruments of the Company contain restrictions and covenants, all of which we were in compliance with at contain restrictions and covenants, all of which we were in compliance with Certain debt instruments of the Company (b) (a) Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): Scheduled maturities of long-term debt, (5) ______31, 2013. (4) Annual Report on Form 10-K for further information. W our subsidiaries. indemnification for reclamation and surety bonds. (3) (in thousands): Dec. 31 was as follows debt outstanding at Long-term W associated with our floating rate debt interest rate swap agreements to reduce our exposure to interest rate fluctuations obligations. See Note information. 198 |10K FORM 10K Long-term debt Notes payable Cash andcashequivalents For additionalinformationsee Note Long-T 2013 NotesPayablerepresentsourRevolvingCreditFacility while2012alsoincludescertaincorporatetermloans. Notes Payable arising fromholdingthesefinancialinstrumentsisminimal. government agencyandinvolveinvestmentriskincluding possiblelossofprincipal. our bank.Repurchaseagreementsarenotdepositsandinsured bytheU.S.Government,FDICoranyother deposits. Included incashandequivalentsiscash,overnightrepurchase agreementaccounts,moneymarketfundsandterm Cash andEquivalents (b) (a) ______The estimatedfairvaluesofourfinancialinstrumentsatDec.31wereasfollows(inthousands): (6) market interestratesfluctuate. reported inpre-taxearningsduringthenext Based onDec.31,2013marketinterestratesandbalances,alossofapproximately (b) (a) ______On Dec.31ourinterestrateswapsandrelatedbalanceswereasfollows(dollarsinthousands): Cash collateralreceivable(payable)includedinderivatives Pre-tax accumulatedothercomprehensive(loss) Non-current derivativeliabilities Current derivativeliabilities Maximum termsinyears Weighted averagefixedinterestrate Notional therefore isclassifiedinLevel2thefairvaluehierarchy Long-term debtisvaluedbasedonobservableinputsavailableeitherdirectlyorindirectlyforsimilarliabilitiesinactivemarketsand market ratesandthereforeisclassifiedinLevel1thefairvaluehierarchy Carrying valueapproximatesfairduetoeithershort-termlengthofmaturity interest rateswapsof Included ontheCondensedStatementsofIncomeParentisnon-cashmark-to-marketgainsrecordedtheseDe-designated Maximum termsinyearsreflecttheamendedearlyterminationdates. erm Debt F
As partofourcashmanagementprocess,excessoperating cashisinvestedinovernightrepurchaseagreementswith AIR (a) V (b) ALUE OF $30 millionand (a) FINANCIAL 3 oftheseBlackHillsCorporation (theParent)CondensedFinancialStatements. $1.9 million INSTRUMENTS 12 months.Estimatedandrealizedlosseswillchangeduringthefutureperiodsas forthetwelvemonthsended $ $ $ . Carrying Amount 198 1,000,000 82,500 1,664 These swapsweresettledin2013. 2013 . $ $ $ $ $ $ $ Fair Value Interest Rate Dec. 31,2013and2012,respectively orvariableinterestratesthatapproximateprevailing 1,028,384 Swaps 2013 82,500 75,000 (9,088 1,664 $3.5 million 5,614 3,474
W 4.97%
— e believehowever 3.0 ) $ $ $ $ $ $ $ $ Interest Rate wouldberealizedand Carrying Amount Swaps (12,721 75,000 550,000 277,000 9,252 3,469 4.97% 1,266 — , thatthemarketrisk 4.0 2012 ) 2012 $ $ $ $ $ . $ $ $ De-designated Interest Rate Swaps Fair Value
250,000 88,148 615,239 277,000 5,960 (a) (b) 5.67% 1,266 — — 1.0 FORM 10K 10K | 199 768 1,237 1,661 , we Balance at End of Year $ $ $ ) ) ) (6,628 (9,045 (7,310 of the Notes to the 1 of the Notes 1 and Other Write-offs Deductions $ $ $ e have also agreed to indemnify our e have also agreed to W 1 3,822 5,369 4,999 ACCOUNTS Additions and Other Recoveries AND 201 $ $ $ TION 1,913 3,042 2,780 (in thousands) AND QUALIFYING Expenses Costs and Additions 199 Charged to $ $ $ TION SCHEDULE II — — — , there can be no assurance that the actual amounts required to satisfy that the actual amounts required , there can be no assurance Annual Report on Form 10-K. Annual Report ALUA V BLACK HILLS CORPORA Adjustments $ $ $ TED YEARS ENDED DEC. 31, 2013, 2012, YEARS ENDED DEC. 31, 2013, 2012, 768 1,661 2,295 e believe the amounts provided in the condensed financial statements are adequate in light of provided in the condensed financial e believe the amounts Year AND CONTINGENCIES W CONSOLIDA Balance at Beginning of $ $ $ 1, we settled the equity forward agreement. For additional information see Note information agreement. For additional the equity forward 1, we settled ficers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not as amended. Certain agreements in accordance with our articles of incorporation, ficers and employees OCK COMMITMENTS COMMITMENTS ST 2012 2011 2013 Description Allowance for doubtful accounts: Consolidated Financial Statements included in this included in this Financial Statements Consolidated (8) In November 201 In November and other matters asserted lawsuits, actions, proceedings, claims of business, we are subject to various In the normal course under laws and regulations. (7) Equity Issuance Forward In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as that include indemnification in favor of of business, we enter into agreements In the normal course and lease contracts. agreements, purchase and sale agreements information technology the probable and estimable contingencies. However the probable and estimable with applicable laws and other matters discussed, and to comply various legal proceedings, claims and alleged liabilities from financial statements. exceed the amounts reflected in the condensed regulations, will not directors, of it is not possible to estimate our potential liability under these contain any limits on our liability and therefore, recourse against third parties with respect to these indemnities. Further indemnifications. In certain cases, we have coverage against certain claims under these indemnities. maintain insurance policies that may provide 200 |10K FORM 10K 3. 10.3*† 10.2*† 10.1*† 4.3* 4.2* 4.1* 3.2* 3.1* 2.2* 2.1* Number Exhibit Exhibits to theRegistrant’sForm10-Qforquarterlyperiodended June30,2011). First AmendmenttotheRestorationPlanofBlackHillsCorporation datedJuly24,2011(filedasExhibit10.2 Restoration PlanofBlackHillsCorporation(filedasExhibit 10.5totheRegistrant’sForm10-Kfor2008). K for2008). 2005 PensionEqualizationPlanofBlackHillsCorporation (filedasExhibit10.3totheRegistrant’sForm10- 10-K for2008). Restated PensionEqualizationPlanofBlackHillsCorporation (filedasExhibit10.2totheRegistrant’sForm (filed asExhibit10.10totheRegistrant’sForm10-Kfor2002). GrandfatherAmendmenttotheAmendedand as Exhibit10.11totheRegistrant’sForm10-K/Afor2001). FirstAmendmenttoPensionEqualizationPlan Amended andRestatedPensionEqualizationPlanofBlack HillsCorporationdatedNovember6,2001(filed Registrant’s Form10-Kfor2000). Form ofStockCertificateforCommonStock,ParValue$1.00PerShare(filedasExhibit4.2tothe Registrant’s RegistrationStatementonFormS-3(No.333-150669)). of NewYorkMellon(filedasExhibit4.21totheRegistrant’sPost-EffectiveAmendmentNo.2 Second SupplementalIndenture,datedasofOctober27,2009,betweenBlackHillsPower,Inc.andTheBank York Mellon(assuccessortoJPMorganChaseBank),asTrustee(filedExhibit4.20theRegistrant’sPost- Supplemental Indenture,datedasofAugust13,2002,betweenBlackHillsPower,Inc.andTheBankNew Amendment No.1totheRegistrant’sRegistrationStatementonFormS-3(No.333-150669)).First Hills Power,Inc.)datedasofSeptember1,1999(filedExhibit4.19totheRegistrant’sPost-Effective Restated andAmendedIndentureofMortgageDeedTrustBlackHillsCorporation(nowcalled Registrant’s Form8-KfiledonNovember18,2013). July 15,2010).FourthSupplementalIndenturedatedasofNovember19,2013(filedExhibit4tothe Third SupplementalIndenturedatedasofJuly16,2010(filedExhibit4toRegistrant’sForm8-Kfiledon Indenture datedasofMay14,2009(filedExhibit4totheRegistrant’sForm8-Kfiledon2009). Exhibit 4.2totheRegistrant’sForm10-QforquarterlyperiodendedJune30,2003).SecondSupplemental for thequarterlyperiodendedJune30,2003).FirstSupplementalIndenturedatedasofMay21,2003(filed successor toLaSalleBankNationalAssociation),asTrustee(filedExhibit4.1theRegistrant’sForm10-Q Indenture datedasofMay21,2003betweentheRegistrantandWellsFargoBank,NationalAssociation(as Form 8-KfiledonFebruary3,2010). Amended andRestatedBylawsoftheRegistrantdatedJanuary28,2010(filedasExhibit3toRegistrant’s Restated ArticlesofIncorporationtheRegistrant(filedasExhibit3toRegistrant’sForm10-Kfor2004). 2012). upon request)(filedasExhibit2totheRegistrant’sForm10-QforquarterlyperiodendedSeptember30, schedules, whichtheRegistrantagreestofurnishsupplementallySecuritiesandExchangeCommission Production, Inc.andothersellersQEPEnergyCompany,asPurchaser(excludingexhibitscertain Purchase andSaleAgreement,datedasofAugust23,2012,byamongBlackHillsExploration (filed asExhibit10.1totheRegistrant’sForm10-QforquarterlyperiodendedMarch31,2012). Regulated HoldingsLLCforthepurchaseofcapitalstockEnsercoEnergyInc.,datedJanuary18,2012 Stock PurchaseAgreementbyandbetweenTwinEagleResourceManagement,LLCBlackHillsNon- 200 Description FORM 10K 10K | 201 201 Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the (filed as Appendix Plan (”Omnibus Plan”) Omnibus Incentive Corporation 2005 Black Hills (filed as Exhibit to the Omnibus Plan First Amendment filed April 13, 2005). Proxy Statement Registrant’s 10 to (filed as Exhibit to the Omnibus Plan Amendment 10-K for 2008). Second Registrant’s Form 10.11 to the 8-K filed on May 26, 2010). the Registrant’s Form 1, 2009 for awards granted on or after January Agreement for Omnibus Plan effective Form of Stock Option to the Registrant’s Form 10-K for 2008). (filed as Exhibit 10.13 1, 2014. for awards granted on or after January Agreement for Omnibus Plan effective Form of Stock Option after January Plan effective for awards granted on or Stock Award Agreement for Omnibus Form of Restricted for 2008). 10.15 to the Registrant’s Form 10-K 1, 2009 (filed as Exhibit 1, 2014. for awards granted on or after January Stock Award for Omnibus Plan effective Form of Restricted for Omnibus Plan effective for awards granted on or after Form of Restricted Stock Unit Award Agreement January 1, 2014. for Omnibus Plan effective for awards granted on or after Form of Performance Share Award Agreement to the Registrant’s Form 10-K for 2009). Form of Performance Share January 1, 2010 (filed as Exhibit 10.11 for awards granted on or after January 1, 2012 (filed as Exhibit Award Agreement for Omnibus Plan effective 10.10 to Registrant’s Form 10-K for 2011). for Omnibus Plan effective for awards granted on or after Form of Performance Share Award Agreement January 1, 2014. Plan effective for awards granted on or after January 1, 2010 (filed Form of Short-term Incentive for Omnibus 10-Q for the quarterly period ended March 31, 2010). as Exhibit 10.1 to the Registrant’s Form as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, Form of Indemnification Agreement (filed 2004). 15, 2013 between Black Hills Corporation and David R. Emery Change in Control Agreement dated November Form 8-K filed on November 19, 2013). (filed as Exhibit 10.1 to the Registrant’s its non-CEO Senior Executive Form of Change in Control Agreements between Black Hills Corporation and 19, 2013). Officers (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on November effective January 1, 2009 (filed Outside Directors Stock Based Compensation Plan as Amended and Restated the Outside Directors Stock as Exhibit 10.23 to the Registrant’s Form 10-K for 2008). First Amendment to the Registrant’s Form 10-K for Based Compensation Plan effective January 1, 2011 (filed as Exhibit 10.16 to Plan effective January 1, 2010). Second Amendment to the Outside Director’s Stock Based Compensation 2013 (filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2012). (filed as Exhibit 10.19 to the Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees Registrant’s Form 10-K for 2011). J.P. Morgan Chase Bank, Credit Agreement, dated June 21, 2013 among Black Hills Corporation, as Borrower, and as a Bank, and the N.A., in its capacity as administrative agent for the Banks under the Credit Agreement, on June 24, 2013). other Banks party thereto (filed as Exhibit 10 to the Registrant’s Form 8-K filed Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective Restated and Plan as Amended Compensation Deferred Non-qualified Hills Corporation Black for 2010). Form 10-K 10.4 to the Registrant’s 2011 (filed as Exhibit January 1, 10.6*† 10.7† 10.8*† 10.9† 10.10† 10.11*† 10.12† 10.13*† 10.14*† 10.15*† 10.16*† 10.17*† 10.18*† 10.19* 10.5*† 10.4*† 202 |10K FORM 10K (b) (a) † * ______101 99 95 32.2 32.1 31.2 31.1 23.2 23.1 21 10.22* 10.21* 10.20* See (a)2.Schedulesabove. See (a)3.Exhibitsabove. Indicates aboardofdirectorormanagementcompensatoryplan. Previously filedaspartofthefilingindicatedandincorporatedby referenceherein. -DatedOctober -ModifiedJanuary22,1990(filed -ModifiedJanuary22,1990(filed -Dated -ModifiedJanuary22,1990(filed Financial StatementsinXBRLFormat Report ofCawley,Gillespie&Associates,Inc. Mine SafetyandHealthAdministrationData of theSarbanes-OxleyAct2002. Certification ofChiefFinancialOfficerpursuantto18U.S.C.Section1350,asadopted906 906 oftheSarbanes-OxleyAct2002. Certification ofChiefExecutiveOfficerpursuantto18U.S.C.Section1350,asadopted adopted pursuanttoSection302oftheSarbanes-OxleyAct2002. Certification ofChiefFinancialOfficerpursuanttoRule13a-14(a)theSecuritiesExchangeAct1934,as as adoptedpursuanttoSection302oftheSarbanes-OxleyAct2002. Certification ofChiefExecutiveOfficerpursuanttoRule13a-14(a)theSecuritiesExchangeAct1934, Consent ofPetroleumEngineerandGeologist. Independent Auditors’Consent. List ofSubsidiariesBlackHillsCorporation. McGee CoalCorporation(filedasExhibit10(u)totheRegistrant’sForm10-Kfor1997). Assignment ofMiningLeasesandRelatedAgreementeffectiveMay27,1997,betweenWRDCKerr- -DatedMay1,1959(filed Coal Leasesbetween and theotherbankspartythereto(filedasExhibit10toRegistrant’sForm8-KfiledonFebruary3,2012). Association, initscapacityasadministrativeagentfortheBanksunderCreditAgreement,andaBank, Credit Agreement,datedFebruary1,2012,amongBlackHillsCorporation,asBorrower,U.S.Bank,National April 1, 1961(filedasExhibit 1, 1965(filedasExhibit WRDC andtheFederalGovernment as Exhibit5(i) as Exhibit as Exhibit as Exhibit 5(j) totheRegistrant’ 5(k) totheRegistrant’ to theRegistrant’ 202 10(j) totheRegistrant’ 10(i) toRegistrant’ 10(h) totheRegistrant’ s Form s Form s Form s Form s Form s Form File No. File No. File No. for 1989) for 1989). for 1989) FORM 10K 10K | 203 February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 February 25, 2014 Act of 1934, the Registrant has duly the Registrant has Act of 1934, Act of 1934, this report has been signed below by the Act of 1934, this report /S/ DAVID R. EMERY /S/ DAVID TURES 203 Director and Principal Executive Officer Principal Executive Principal Financial and Accounting Officer Director Director Director Director Director Director Director Director Director BLACK HILLS CORPORATION BLACK HILLS By: President David R. Emery, Chairman, Officer and Chief Executive SIGNA February 25, 2014 /S/ DAVID R. EMERY David R. Emery, Chairman, President David R. Emery, Chairman, and Chief Executive Officer /S/ ANTHONY S. CLEBERG Anthony S. Cleberg, Executive Vice President and Chief Financial Officer /S/ JACK W. EUGSTER Jack W. Eugster /S/ MICHAEL H. MADISON Michael H. Madison /S/ STEVEN R. MILLS Steven R. Mills /S/ STEPHEN D. NEWLIN Stephen D. Newlin /S/ GARY L. PECHOTA Gary L. Pechota /S/ REBECCA B. ROBERTS Rebecca B. Roberts /S/ WARREN L. ROBINSON Warren L. Robinson /S/ JOHN B. VERING John B. Vering /S/ THOMAS J. ZELLER Thomas J. Zeller Dated: Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange of the Securities of Section 13 or 15(d) the requirements Pursuant to of the Securities Exchange Pursuant to the requirements following persons on behalf of the Registrant and in the capacities and on the dates indicated. behalf of the Registrant and in the capacities following persons on caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. undersigned, thereunto on its behalf by the report to be signed caused this FORM 10K (This page left mostly blank intentionally.) blank mostly left page (This BIOS BIOS | 205 age 58, age was the elected to
Steven Mills, Steven Board Directors of in 2011. Mills Mr. was Financial Chief of Officer Amyris, Inc., products an integrated renewable 2012 from May December to company, 2013. was He Executive Senior Vice Newlin,Stephen 61, was age theelected Board to Directors of in 2004 and currently chairs the Governance Committee. Newlin Mr. has been Chairman, and President PolyOne ExecutiveChief of Officer President PerformancePresident and Growth Archer of transporter, a processor, Daniels Midland Company, agricultural and marketer of buyer products, from February to 2010 2012, Executive President Vice Financialand Chief Officer from 2008and to2010 President, Planning Strategic Vice Senior from 2006 to 2008. of provider premier Corporation, a global specialized materials, polymer services and since 2006.solutions, the was of He President Industrial of Inc., Ecolab, leader Sector of a global services, specialty serving chemicals and equipment industrial and institutional clients, from 2003 to 2006. also He serves the board on directors of of Oshkosh Corporation. age 68, age was elected to
age 51, age David Emery, was elected Chairman in April 2005 and has been Executive and Chief OfficerPresident the Board of Directorsand a member of since January 2004. he Previously, was Operating and Chief our President Eugster, Jack the Board Directors of in 2004 and currently chairs the Compensation wasCommittee. Chairman, Eugster Mr. ExecutiveChief Officerand President Stores, Inc. from 1980 Musicland of Michael Madison, 65, age was elected the Boardto Directors of in 2012. Mr. Madison was President, Executive Chief OfficerCleco and a of Director utility Corporation, a public holding from 2005 2011. to company, was He
Officer - Retail AprilBusiness Segment from to 2003 January 2004 Resources – Fuel President and Vice from January 1997 April to 2003. until his retirement in 2001. was He Non-Executive Chairman Stores, Inc., a general Shopko of merchandise discount chain, store from 2001 to 2005. also He serves the board on directors of of Graco, Inc. and Fitness, Life Inc. Time OperatingCleco and Chief President of Officer LLC, from 2003Power, 2005 to President, and State Louisiana-Arkansas with American Electric Power, from 2000 2003. to
Black Hills Corporation Board Directors of Report Annual 2013 206 |BIOS BIOS 1992 until his retirement in January 2006. January in retirement his until 1992 company,andresources energy from a diversified Company. Appliances Safety Mine and LLC, Management, Energy of Company, Enbridge Energy Enbridge Inc., on the board of directors of Insteel Industries, Inc. Industries, of Insteel of directors on board the serves andalso accounting. He positions finance in and held positions cement executive the in industry He previously to 2005. Commission 2003 from Gaming the Chief of HeIndian of National Staff was 2006. She also serves on the board of directors of directors on board the serves She also 2006. Global to PowerChevron Generation 2003 from President She of was 2011. to February 2006 from United the States, within chemicals and gas natural Officer of MDU Resources Group, Inc., Group, Resources Officer of Inc., MDU Treasurer President, Chief and Financial Vice Executive Mr. was Robinson Audit the Committee. chairs currently and 2007 in of Directors to Board the Warren Robinson, Rebecca Roberts, Rebecca to 2007. 2005 from retired He was 2007. company, services since billing medical Officer of a Inc., DT-TRAK Consulting, President Chief been and Executive has Mr. Pechota 2007. in of Directors Board to elected the was age 64, Pechota, Gary products, liquefied petroleum gas, liquefiedpetroleum gas, products, petroleum refined oil, crude transporting Company, Line Pipe apipeline company President of was Chevron Roberts Ms. 2011. in of Directors to Board the age 61, was elected elected age was 61, age 63, was elected elected was age 63,
1995 to January 2011. 2011. to January 1995 President as from served and 2011 to August 2011 protection January protocols, from environmental emerging in specializing resources natural and technologies information water and engineering, industry. gas and oil the in positions executive He held previously several 2011. May from 2010 subsidiary, to gas and December oil our Exploration Inc., Production, and of Black Hills and services firm with expertise in expertise with firm services and consulting atechnical of RESPEC, Officer Chief Executive was Mr. Zeller Director. Presiding as serves currently and 1997 in of Directors to Board the elected Zeller, was ageThomas 66, Interim President and General Manager Manager General and President Interim as He served 2002. since investments, gas and oil Inc., Investments, Mountain of Lone Director Managing been has Mr. Vering 2005. in of Directors Board John Vering, age 64, was elected to elected the was age 64, BIOS BIOS | 207
age 57, hasSteven Helmers, been J. 57, age our Senior Vice President, General Officer Counsel Compliance and Chief since January 2008. served He as our Senior Vice President, General Counsel since January 2004 Vice and our Senior Robert A. 56, Myers, age has been our Human – Chief President Vice Senior Resources Officer Januarysince 2009 and served as our Interim Human Resources 2008. Executive since June wasHe a partner with Talent Strategic Linden R. Evans, 51, age has been Operating and Chief President Officer – Utilities since October 2004. Evans served and as General the President Vice communication our former Manager of subsidiary from December 2003 to
12 years experience of with the company. October 2004 and served as our Associate Counsel 2001from May December 2003. to Evans Mr. has President, General Secretary Counsel and Corporate from 2001 2004. to Helmers Mr. has 13 years of experience with the company. a human resourcesSolutions, consulting firm, from October 2006 until December 2008, Senior Human – Chief Resource President for Vice Officer EnergyDevon from March 2006 until September 2006, Human and Chief President Vice and Senior Resource at Officer International, Reebok Ltd from 2003November until January 2006. has He more than 33 years service of in key human resources leadership roles.
Anthony S. 61, Cleberg, has age been and Chief Executive President Vice Financial Officer Julysince 2008. He developer investor, was an independent and consultant with in companies from 2002 and Wyoming untilColorado Scott A. Buchholz, 52, age has been – Chief President Vice our Senior of OfficerInformation close sincethe the Aquila transaction in 2008. July was he joining theBefore company, Information of President Vice Aquila’s age 51, age David Emery, was elected Chairman in April 2005 and has been Executive and Chief OfficerPresident the Board of Directorsand a member of since January 2004. he Previously, was Operating and Chief our President
joining the company injoining the 2008. company his Before consulting was he androle, the Chief Executive President Vice Financialcompanies: of Officer publicly traded two International, Group, Inc.,Washington a large engineering and construction in involved company construction plant power and mining operations, Enterprises,and Champion factory-built of a builder 15 spent his roles, he years Before CFO housing. in various financial senior Honeywell positions with International, years Inc. in and public eight LLP. & Touche, Deloitte at accounting Technology from June 2005 from June untilTechnology 2008, July Six from Belt January Leader/Black Deployment Sigma 2004 until 2005, June and General Manager, Corporate Information Technology from February 2002 until January 2004. with was He employed Aquila 28 years. for Officer - Retail AprilBusiness Segment from to 2003 January 2004 Resources – Fuel President and Vice from January 1997 April to 2003. Emery Mr. has
24 years experience of with the company.
Executive Officers Black Hills Corporation Executive Report Annual 2013 BIOS (This page left mostly blank intentionally.) blank mostly left page (This MONTANA SOUTH DAKOTA Investor Information 39 utility customers 2 communities served 66,389 utility customers 2013 Annual Report 558 employees 23 communities served 155 megawatts of operated WYOMING power generation capacity Common Stock 2014 Annual Meeting 78,639 utility customers IOWA 291 employees Transfer Agent, Registrar & Dividend Disbursing Agent The Annual Meeting of Shareholders will be held at The Dahl 7 communities served 153,458 utility customers Wells Fargo Shareowner Services Arts Center, 713 Seventh Street, Rapid City, South Dakota, 301 operated oil & gas wells 183 employees P.O. Box 64854 at 9:30 a.m. local time on April 29, 2014. Prior to the meeting, 29 bcfe reserves 132 communities served St. Paul, Minnesota 55164-0854 formal notice, proxy statement and proxy will be mailed 213 million tons of 800-468-9716 to shareholders. coal reserves www.wellsfargo.com/shareownerservices 520 megawatts of operated NEBRASKA Market for Equity Securities power generation capacity Senior Unsecured Notes – Black Hills Corporation The Company’s Common Stock ($1 par value) is traded 198,504 utility customers Trustee & Paying Agent on the New York Stock Exchange (NYSE). Quotations for 435 employees Wells Fargo Bank, N.A. the Common Stock are reported under the symbol BKH. COLORADO 106 communities served 750 N. St. Paul Place, Suite 1750 The continued interest and support of equity owners are Dallas, Texas 75201 appreciated. The Company has declared Common Stock 168,351 utility customers dividends payable in each year since its incorporation in 313 employees First Mortgage Bonds – Black Hills Power, Inc. 1941. Regular quarterly dividends when declared are normally 52 communities served KANSAS The Bank of New York Mellon payable on March 1, June 1, September 1 and December 1. 69 operated oil & gas wells 111,683 utility customers 101 Barclay Street, 8W 25 bcfe reserves 146 employees New York, New York 10286 Internet Account Access 425 megawatts of operated 62 communities served power generation capacity Registered shareholders can access their accounts First Mortgage Bonds – Cheyenne Light, Fuel & Power electronically at www.shareowneronline.com. Shareowner Trustee & Paying Agent Online allows shareholders to view their account balance, Wells Fargo Bank, N.A. dividend information, reinvestment details and much more. NEW MEXICO 750 N. St. Paul Place, Suite 1750 The transfer agent maintains stockholder account access. Dallas, Texas 75201 14 employees Direct Deposit of Dividends 135 operated oil & gas wells We encourage you to consider the direct deposit of your 24 bcfe reserves Pollution Control Refunding Revenue Bonds – Black Hills Power, Inc. dividends. With direct deposit, your quarterly dividend Trustee & Paying Agent payment can be automatically transferred on the dividend Wells Fargo Bank, N.A. payment date to the bank, savings and loan, or credit union 625 Marquette Ave., 11th floor of your choice. Direct deposit assures payments are credited Minneapolis, Minnesota 55479 to shareholders’ accounts without delay. A form is attached to Electric Utilities your dividend check where you can request information about Environmental Improvement Revenue Bonds this method of payment. Questions regarding direct deposit Natural Gas Utilities – Black Hills Power, Inc. should be directed to Wells Fargo Shareowner Services. Trustee & Paying Agent Power Generation The Bank of New York Mellon Dividend Reinvestment and Direct Stock Purchase Plan 1775 Sherman Street, Suite 2775 A Dividend Reinvestment and Direct Stock Purchase Plan Coal Mine Denver, Colorado 80203 provides interested investors the opportunity to purchase shares of the Company’s Common Stock and to reinvest Oil and Gas Industrial Development Revenue Bonds all or a percentage of their dividends. For complete details, 43 Consecutive Years of Dividend Increases – Cheyenne Light, Fuel & Power including enrollment, contact the transfer agent, Wells Fargo Corporate Office Trustee & Paying Agent Shareowner Services. Plan information is also available at US Bank National Association www.wellsfargo.com/shareownerservices. Company Headquarters 950 17th Street, Suite 1200 $1.52 $1.48 $1.46 $1.44 $1.42 Denver, Colorado 80202 Website Access to Reports $1.40 $1.37
$1.28 The reports we file with the SEC are available free of charge Corporate Offices at our website www.blackhillscorp.com as soon as reasonably $1.08 Black Hills Corporation practicable after they are filed. In addition, the charters of our $0.89 P.O. Box 1400 Audit, Governance and Compensation Committees are located $0.73 625 Ninth Street on our web site along with our Code of Business Conduct,
$0.21 Rapid City, South Dakota 57701 Code of Ethics for our Chief Executive Officer and Senior $0.13 $0.11 $0.43 605-721-1700 Finance Officer, Corporate Governance Guidelines of our 1970 1975 1980 1985 1990 1995 2000 2005 2007 2008 2009 2010 2011 2012 2013 www.blackhillscorp.com Board of Directors and Policy for Independent Directors.
Some of the sections in this annual report contain forward-looking statements. For a discussion about factors that could affect operating results, please see the Risk Factors beginning on page 51 of the Form 10-K. BKH | 2013 BKH Black Hills Corporation | Annual Report | Proxy Statement | Form 10K | Form Statement | Proxy Report | Annual Growth 2013 Black Hills Corporation
Annual Report Proxy Statement Form 10K
www.blackhillscorp.com
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