GREAT RIVER ENERGY 2 0 1 3

ANNUAL REPORT 655,000 homes, farms and businesses served by .

4,660 miles of transmission line, . . 12 power plants and . 880 employees for .

28 member cooperatives focused on .

1 vision .

. KEEP COOPERATIVE ENERGY COMPETITIVE

C ONTENTS

Letter to stakeholders...... 2

About Great River Energy...... 4

Reliable resources...... 6

Generation: Energy that never stops...... 8

Transmission: Wired to serve...... 12

Members: Partners in power...... 16

2013 financial report...... 20

Management and board of directors...... 56

L ETTER TO STAKEHOLDERS

EFFICIENT POWER GENERATION

RELIABLE

TRANSMISSION

STRONG

FINANCES

David Saggau Michael Thorson

Great River Energy Great River Energy President and CEO Board Chair

cooperatives, Great River Energy enters During periods of uncertainty, a 2014 better prepared to face them. company can choose to wait for clarity or take action. In many ways, 2013 was among the best financial years in our history. Our margin Great River Energy has thrived in recent exceeded budget by more than $10 million, years because we have discovered and we were able to budget for no rate opportunities within the challenges facing increase in 2014. our industry. We are beginning to see

returns from actions taken, and we continue Our success was the result of the prudent

to enact strategies to improve our position in strategies we adopted in response to a

the future. trend of flat energy sales over the previous five years. Among the most significant The challenges facing our industry have not actions were our reduced capital spending changed. But, together with our member plans and heightened focus on reducing

2

expenses in our daily operations. Those to wait for outside forces to dictate our savings are reinforced through our business decisions. As regulatory proposals are improvement program, which systematically discussed, we are analyzing potential encourages employees to pursue efficiencies effects on our business and working with a in their work. variety of organizations to collaborate on solutions to further the position of Great Great River Energy’s board of directors River Energy and our member cooperatives. and company leaders understand that the While we monitor and influence what lies strategies that helped us in recent years will ahead for our industry, we are also taking not be enough to keep us competitive in the action to thrive in the current environment. years ahead. That is why we have already Our margin taken actions to improve our position in The positive results of the past year are not exceeded budget the future. an end result. They are a signal of positive progress and a step toward our mission to by more than $10 Our board of directors passed a resolution continue providing members with reliable in July to mitigate business risk associated million, and we energy at affordable rates in harmony with with pending greenhouse gas regulations. a sustainable environment. were able to That resolution resulted in immediate actions, budget for no rate including accelerating the depreciation of Fifteen years ago, two generation and Great River Energy’s Coal Creek Station transmission cooperatives looked far into the increase in 2014. and Stanton Station. The resolution also future and recognized that they could be charged Great River Energy with engaging better united than apart, so they formed

in the development of the regulations to Great River Energy. That same culture of minimize rate impacts and ensure reliable long-term thinking continues to exist at electric service. Great River Energy to this day.

Although there are still uncertainties ahead The men and women who care for our of us, we are seeking clarity through generation and transmission resources have engagement. This fall, we invited several of the training and experience to maintain our our external stakeholders to Great River system to exacting standards, while working

Energy to discuss our business and the safely. Our member cooperatives and challenges we are facing, and to understand board of directors have the confidence and their views on pressing issues. By welcoming motivation to improve our operations and

the perspectives of end-use consumers, financial performance.

financial institutions, low-income advocates Great River Energy exists because our two and environmental nonprofit organizations, predecessor companies recognized a better we gained valuable insight into the priorities way to achieve their goal of providing of those with a vested interest in cooperative reliable, low-cost power to their member electricity in Minnesota. distribution cooperatives. Our success in We are determined to act strategically in 2013 is the result of a continued focus on

the best interests of our members, and not that same goal.

3 A BOUT GREAT RIVER ENERGY

GREAT RIVER ENERGY IS A NOT-FOR-PROFIT COOPERATIVE WHICH PROVIDES WHOLESALE ELECTRIC SERVICE TO 28 DISTRIBUTION COOPERATIVES IN MINNESOTA AND WISCONSIN. THOSE MEMBER COOPERATIVES DISTRIBUTE ELECTRICITY TO APPROXIMATELY 655,000 MEMBER

ACCOUNTS – OR ABOUT 1.7 MILLION PEOPLE. WITH

$3.7 BILLION IN ASSETS, GREAT RIVER ENERGY IS THE . SECOND LARGEST ELECTRIC POWER SUPPLIER IN . . . MINNESOTA AND ONE OF THE LARGEST GENERATION AND . .

TRANSMISSION COOPERATIVES IN THE UNITED . . . STATES. GREAT RIVER OUR MEMBER . COOPERATIVES ENERGY’S MEMBER . . COOPERATIVES RANGE

FROM THOSE IN THE OUTER- . RING SUBURBS OF THE TWIN CITIES

TO THE ARROWHEAD REGION OF .

MINNESOTA TO THE FARMLAND OF SOUTHWESTERN MINNESOTA. GREAT . RIVER ENERGY’S LARGEST DISTRIBUTION . COOPERATIVE SERVES MORE THAN 125,000 MEMBER-CONSUMERS; THE SMALLEST SERVES ABOUT 2,500. LEARN MORE AT GREATRIVERENERGY.COM.

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Member Cooperative Summary Great River Energy 2013 Systemwide Load

Financial Highlights Characteristics* Number of member accounts...... 655,000 Revenue...... $980.4 million Residential...... 55.6% Sales to members ...... 12,105,295 $3.7 1.6 megawatt hours Total assets ...... billion Seasonal...... %

Total distribution line... 88,000 miles Utility plant Commercial, industrial investment (net)...... $2.7 billion and other...... 42.8%

Average density. 7.5 consumers/mile Long-term obligations, including *Based on energy sales Distribution substations...... 553 current maturities...... $2.7 billion

Combined annual

revenue...... $1.35 billion

Electric plant in service (net)...... $1.9 billion

Average kilowatt hours per account...... 18,000/year Distribution employees...... 1,575

5 GENERATION

E L I A B L E R 1 4

RESOURCES Coal Creek Station Elk River Energy Recovery Station Location: Underwood, N.D. Location: Elk River, Minnesota PROVIDING DEPENDABLE Generating capability: 1,142 MW Generating capability: 31 MW Start of operation: Start of operation: Units 1 & 2, 1951; Unit 1, 1979; Unit 2, 1980 Unit 3, 1959 WHOLESALE ELECTRICITY TO Fuel: Lignite coal and DryFineTM Fuel: Refuse-derived fuel lignite coal GREAT RIVER ENERGY’S

MEMBER COOPERATIVES

REQUIRES A WELL

MAINTAINED AND FLEXIBLE

RESOURCE PORTFOLIO THAT

2 INCLUDES GENERATION Stanton Station FACILITIES OF A VARIETY OF Location: Stanton, N.D. Generating capability: 187 MW SIZES AND FUEL TYPES AND A Start of operation: Unit 1, 1966; Unit 10, 1982 WIDESPREAD NETWORK OF Fuel: Powder River Basin coal

TRANSMISSION LINES.

3 7

Spiritwood Station Lakefield Junction Station

Location: Jamestown, N.D. Location: Martin County, Minnesota Generating capability: 99 MW Generating capability: 522 MW (summer) Start of operation: November 2014 Start of operation: 2001 Fuel: DryFine lignite coal Fuel: Natural gas; backup, fuel oil

TRANSMISSION

GREAT RIVER ENERGY MAINTAINS 4,660 MILES OF TRANSMISSION LINE AND OWNS OR PARTIALLY OWNS 102 TRANSMISSION SUBSTATIONS.

±400 kilovolt (kV) DC 436 mi 500 kV 70 mi 345 kV 75 mi

6 9 St. Bonifacius Station 12 Arrowhead Emergency Location: St. Bonifacius, Minnesota Generation Station Generating capability: Location: Cook County, Minnesota 56 MW (summer) Generating capability: 18 MW Fuel: Fuel oil Fuel: Fuel oil

10 Rock Lake Station 13 Trimont Wind Location: Pine City, Minnesota Purchase: 100 MW (nameplate) Generating capability: Turbine: 67 General Electric 1.5-MW 5 6 19 MW (summer) wind turbines Fuel: Fuel oil Elk River Peaking Station Cambridge Station 14 Elm Creek Wind Location: Elk River, Minnesota Location: Cambridge, Minnesota 11 Maple Lake Station Purchase: 99 MW (nameplate) Generating capability: 185 MW* (summer) Generating capability: 177 MW* (summer) Location: Maple Lake, Minnesota Turbine: 66 General Electric 1.5-MW Start of operation: 2009 Start of operation: 2007 Generating capability: wind turbines Fuel: Natural gas; backup, fuel oil Fuel: Fuel oil (Unit 1), and natural gas 19 MW (summer) (Unit 2) Fuel: Fuel oil 15 Prairie Star Wind Purchase: 101 MW (nameplate) Turbine: 61 Vestas 1.65-MW wind turbines

16 Ashtabula II Wind Purchase: 51 MW (nameplate) Turbine: 34 General Electric 1.5-MW wind turbines 17 Endeavor I Wind Purchase: 100 MW (nameplate) Turbine: 40 Clipper 2.5-MW wind turbines

OTHER ASSETS Blue Flint Ethanol Blue Flint Ethanol is a biorefinery that uses process steam from the nearby Coal Creek Station power plant to produce 65 million gallons of ethanol per year. Elk River Resource Processing Plant Municipal solid waste is processed to create refuse- derived fuel (RDF) for powering Great River Energy’s Elk River Energy Recovery Station. Up to 300,000 tons of waste is transformed into RDF each year. Other wind energy purchases: 8 17 MW (nameplate) from four Minnesota wind farms. Location: Jackson, Dodge and Murray counties. Pleasant Valley Station Generating capability based on Summer Net Dependable Location: Mower County, Minnesota Capacity per NERC Generating Availability Data System for Generating capability: 408 MW (summer) the 2014 - 2015 planning year. Start of operation: Units 11 & 12, 2001; *Based on the 2013 - 2014 planning year. Unit 13, 2002 Fuel: Natural gas; backup, fuel oil

230 kV 523 mi 161 kV 46 mi 115 kV 468 mi 69 kV or less 3,024 mi

7 ENERGY

THAT NEVER

STOPS

Flexible generation resources, dependable fuel supplies, second-to-none maintenance and an ever-present focus on

the safety of employees and

members add up to the quality of service Great River Energy provides for its member cooperatives.

Great River Energy’s peaking plants are meticulously maintained so they are ready to produce electricity immediately when demand increases. Peaking Plant Operator Tech Kevin Beske performs maintenance checks at Pleasant Valley Station near Dexter, Minnesota. 8 B uilt on a foundation of two workhorse Energy renewed its contract with Hennepin coal-based power plants complemented County to receive up to 100,000 tons of by peaking stations and widespread solid waste for the next five and a half renewable resources, Great River years to supply fuel to the facilities. Energy’s generation portfolio has been The contract ensures a dependable crafted over decades for reliability, supply of waste, allowing the entire Great River Energy’s affordability and environmental project to operate efficiently. The project power supply portfolio performance. Each source is important to generates revenue for Great River consists of a diverse meet demand for electricity while Energy by selling steel, aluminum and producing revenue for Great River mix of energy sources. other valuable materials Energy and its member cooperatives. removed from the waste Over the past five years, Great River for recycling, and by Energy’s coal-based resources have been selling electricity into available to generate electricity nearly the market.

93 percent of every year, which Great River Energy consistently exceeds the averages of signed a 200-megawatt other power plants in the region. seasonal diversity Such remarkable plant performance is exchange with Manitoba due to the diligent maintenance Hydro of Winnipeg, performed by Great River Energy extending a employees. In 2013, one of the two units 150-megawatt at Great River Energy’s Coal Creek arrangement that has Station power plant successfully been in place between completed a major scheduled outage to the two utilities since perform preventive maintenance, 1995. The diversity inspections and repairs. Taking a plant exchange means Manitoba offline at regular intervals to perform Hydro will provide 200 maintenance is vital to ensure that the megawatts of renewable hydroelectric plant continues to operate reliably. capacity to Great River Energy in the summer to meet its energy needs, while Great River Energy will provide Bright future for Manitoba Hydro with 200 megawatts of renewable resources capacity during the winter. Each utility The Elk River Resource Recovery Project receives the additional energy during its consists of two facilities: one that peak period of the year. The new processes municipal solid waste to create agreement runs until 2030. a burnable fuel and a power plant that produces renewable energy from the New solar panels will be installed next to resulting refuse-derived fuel. Great River the Great River Energy headquarters

9

During the major scheduled maintenance outage at Great River Energy’s Coal Creek Station, welders repair power plant equipment.

The Elk River facility in Maple Grove, Minnesota, in stay aware of innovations in a rapidly 2014 and throughout the organization’s changing industry. Resource Processing service area through 2015. The first By collaborating with research Plant uses specialized construction project is a 250 kilowatt solar organizations and other utilities, Great array slated for land south of Great River equipment to pull River Energy gains more from its research Energy’s headquarters facility and will steel and aluminum dollars than it ever could acting alone. include a mix of technologies to help These alliances give Great River Energy out of household determine how small solar energy access to a larger body of knowledge installations can be integrated into garbage to be and provide opportunities to develop key cooperative systems. recycled. Each year, contacts. The benefits of research include

Great River Energy is working with its the DryFining™ technology that was the facility removes member cooperatives to identify installed at Coal Creek Station in 2009. 9,000 tons of steel potential sites for 20 kilowatt solar Developed with financial assistance from – roughly as much as installations in their communities. the U.S. Department of Energy, DryFining the Eiffel Tower – and technology is a lignite coal refining 1,500 tons of aluminum Progress through research process that has yielded environmental, efficiency and maintenance benefits. In – the equivalent of At any given time, Great River Energy is involved in several research projects at its 2013, Great River Energy executed a 100 million pop cans. generation facilities. The projects range DryFining License and Technology from studies aimed at reducing emissions Transfer Agreement with Tangshan of mercury, nitrogen oxides and sulfur Shenzhou Manufacturing Company to dioxide to tests for new maintenance make the technology available to utilities practices. Research helps the cooperative in China.

10 Construction is underway for Dakota New ventures keep energy Spirit AgEnergy, a new biorefinery to be competitive co-located next to Spiritwood Station, a Aside from electricity, Great River combined heat and power plant near Energy’s generation facilities produce a Jamestown, North Dakota. The Dakota Revenue from variety of other products and services, Spirit AgEnergy biorefinery will begin ranging from ethanol to corn drying, that commercial operation by the second steam, water, ash increase revenue. In a cooperative quarter of 2015. Completing its investment and other products business model, that revenue directly fund raising substantially during 2013, and services offsets plant costs. Revenue from steam, about half of the construction investment is water, ash and other products and coming from international investors through marked 2013 as a

services marked 2013 as a record year the EB-5 program. The biorefinery will record year.

in value created for the membership to utilize steam from Spiritwood Station in a benefit overall member rates. configuration similar to Blue Flint Ethanol’s, and will produce 65 million gallons of Located adjacent to Coal Creek Station ethanol per year, as well as distillers near Underwood, North Dakota, Blue grains and distillers oil. Flint Ethanol is the first co-located, directly integrated biorefinery in North Both biorefineries are

America – and one of the most cost- owned by Midwest effective, energy efficient and AgEnergy Group, an

environmentally friendly biorefineries in Upper Midwest biofuels

the country. By purchasing steam from enterprise owned by

Great River Energy, Blue Flint Ethanol Great River Energy

saved initial capital by not building a and other private

gas-fired boiler. The flexible steam accredited investors,

supply also contributes other annual both agricultural

operating benefits while Great River and corporate.

Energy enjoys the steam sales revenue. Spiritwood Station will generate electricity as well as steam for the Dakota Spirit AgEnergy biorefinery.

Saggau represents cooperatives on NERC council

Great River Energy President and CEO David Saggau has been selected to represent electric cooperatives around the country on the North American Electric

Reliability Corporation’s Electric Sub-Sector Coordinating Council (ESCC).

Originally formed by Presidential Directive in response to the Sept. 11, 2001, terrorist attacks, the ESCC provides utilities’ perspectives to the federal government on issues as varied as cyber security, natural disasters and other physical security issues related to vandalism or terrorism.

11

WIRED

TO

SERVE

Through carefully constructed and maintained transmission resources, Great River Energy and its member cooperatives consistently deliver exactly the right amount of power to farms, factories and families.

Great River Energy Line Technician J.R. McGuire works to remove capacitors containing polychlorinated biphenyls, a potentially harmful material, from Dickinson Station near Buffalo, Minnesota. 12 P roducing electricity is only the first step Grand Rapids, Minnesota. A new in providing reliable service. Great River transmission line will link a much-needed Energy must also deliver power through substation to the local grid, while a its transmission system. Year after year, second enhancement will increase the Great River Energy’s transmission system capacity of approximately 38 miles of is highly reliable, and 2013 was an existing 69-kilovolt transmission line. no different. Great River Energy tracks the reliability Advancing grid of its transmission system using industry- technology standard indices which measure how In 2013, Great Great River Energy and two of its often outages occur and how long they member cooperatives, Lake Region River Energy last. In 2013, Great River Energy Electric Cooperative of Pelican Rapids, recorded about recorded about half of the typical Minnesota, and Minnesota Valley Electric number of momentary outages, ranking it half of the typical Cooperative of Jordan, Minnesota, have among the best years in the cooperative’s collaborated on a demonstration project number of history. Momentary outages are those to pilot technologies designed to enable momentary lasting less than one minute. future utility programs and services. transmission Two bouts of extreme weather in the first After nearly 18 months of development, outages. half of the year significantly affected the completely new “smart grid” systems Great River Energy’s year-end results for delivered the business and technical total outage hours. A major ice storm functionality ready for demonstration and April 9-11 and a thunderstorm outbreak testing. The project illustrates the potential June 21-22 accounted for about three- business value that Great River Energy quarters of the total outage time in and its member cooperatives can gain 2013. That said, Great River Energy’s from using technology to improve meter system was extremely reliable. data management and demand response management.

New lines for new needs The three cooperatives will continue Due to northern Minnesota homeowners working to improve the technology and increasingly converting from propane to establish business practices to uncover electricity for space heating, the electric additional value from the new capabilities. transmission system in the region has become strained to its limit. The system The project was coordinated by the must be built to handle the periods of National Rural Electric Cooperative highest electricity use, which now occur in Association’s Cooperative Research the winter. Network and is funded in part by a U.S. Department of Energy grant. Two projects are underway to bring relief to the constrained region surrounding

13 The Chub Lake Substation, located in Scott County, Minnesota, is one of two new substations that were needed on the CapX2020 project between Brookings County, South Dakota, and Hampton, Minnesota.

THE BENEFITS Serving the region Technology speeds up

OF CapX2020 at large power restoration For decades, electric utilities built Every moment matters when electric GENERATION transmission lines to serve only their service is interrupted to a home or customers. That changed over the past business. Great River Energy and its The new lines will open decade as regional transmission member cooperatives are testing ways to pathways to centers of operators were formed as independent, use technology to boost system reliability high energy use from areas of power generation, third-party bodies to oversee and grant by sharing real-time electric grid including remote areas access to the grid while creating real- information. with strong wind resources. time energy markets.

They will also make the The cooperatives are piloting a real-time energy market work As this evolution occurred, transmission data interface that will allow cooperatives more efficiently. development was needed to foster a to automate distribution outage processes more efficient and effective electricity and reduce restoration time. RELIABILITY market. These projects are known as regional transmission, and Great River These high-voltage Energy has spent the past several years transmission links assure involved in an extensive buildout of that wide area reliability this kind. will be maintained and make the system less susceptible Known as CapX2020, these lengthy to disturbances. high-voltage projects are needed to

expand electric transmission and ensure ECONOMIC continued reliable and affordable DEVELOPMENT service. CapX2020 is a joint initiative of CapX2020 is an approximately 11 utilities, and Great River Energy is $2 billion investment that construction lead on the 345-kilovolt, will create 8,000 jobs during 240-mile transmission line spanning from A major ice storm in April accounted for a significant portion of total transmission outage time in 2013. Pictured here, crews peak construction and Brookings County, South Dakota, to restore service to a downed transmission line. $3.9 billion in total Hampton, Minnesota. economic impact.

14

Engagement during policy discussions During the first half of 2014, federal accelerating the depreciation of Great greenhouse gas regulations are being River Energy’s Coal Creek Station and drafted that have the potential to impose Stanton Station. Great River Energy will As regulatory new and significant costs on the depreciate these coal-based resources proposals are operations of electric utilities. As a utility by 2028, which is significantly sooner discussed, a Great that will be affected by the resulting than previously planned. The resolution regulations, Great River Energy is also charged Great River Energy with River Energy task determined to be an active participant in reducing its reliance on coal-based force is analyzing their creation. electricity and managing carbon dioxide potential effects on emissions to 2005 levels. Anticipating the likely adoption of the business. greenhouse gas regulations, the Great Great River Energy is also working with

River Energy board of directors passed a a variety of organizations to shape the

resolution enacting a plan to mitigate the proposed regulations to minimize their

risk of the regulations. That resolution financial impact on Great River Energy

resulted in immediate actions, including and its members.

Great River Energy’s Coal Creek Station power plant is located near Underwood, North Dakota, and generates electricity using DryFineTM lignite coal.

15 PARTNERS

IN

POWER

Great River Energy remains in tune with the communities it serves, and that applies to the

communities where its 28 member distribution cooperatives operate and where Great River Energy has

facilities and employees.

Cooperatives find ways to

foster thriving communities.

Great River Energy’s business improvement program encourages employees to streamline practices to keep rates affordable. In 2013, employees discovered an innovative way to correct a deficiency in vital emission control equipment at Coal Creek Station. The solution will save approximately $66 million in future capital spending. The effort involved 16 many employees, including (left to right) Brian Freed, Skip Oberg, Gary Sawicki, Tyler Kinn and Ethan Vaagene.

E lectric cooperatives focus on the needs of the communities they serve, and that Cooperatives commended goes far beyond providing electricity. In for conservation fact, this promise is included in the Great River Energy has long worked with principles that guide all cooperative its member distribution cooperatives to businesses. The “concern for community” offer programs that encourage end-use cooperative principle states that while members to manage electricity costs focusing on member needs, cooperatives through conservation and energy must work for the sustainable development efficiency improvements. Helping of the communities they serve. members use energy wisely not only Great River Energy reduces their costs, but also contributes Healthy communities and strong economies toward more efficient, affordable and has an average go hand in hand. A 2013 study showed reliable electric service. annual economic that Great River Energy’s operations to supply wholesale power throughout Great River Energy coordinates a impact of more greater Minnesota have far reaching portfolio of programs with its members to than $1 billion and positive effects on the region’s economy. encourage homeowners and businesses to 4,000 jobs. replace outdated, inefficient equipment In an analysis of the company’s core with newer, efficient installations. operations, the University of Minnesota- Programs encourage members to pursue Duluth found that Great River Energy has efficient alternatives ranging from small an average annual economic impact of upgrades, such as compact fluorescent more than $1 billion and 4,000 jobs. light bulbs and LED holiday lights, to Great River Energy and its member large installations, such as ground-source cooperatives work closely with the heat pumps, variable frequency drives businesses they serve to ensure they can and manufacturing process improvements. remain competitive by helping them use At the end of 2013, Great River Energy energy wisely and by offering ways to received a letter of commendation from invest in their operations. Great River the Minnesota Division of Energy Resources Energy often helps cooperatives pursue for its 28 member cooperatives’ efforts funding through the U.S. Department of to achieve Minnesota’s Conservation Agriculture’s Rural Economic Development Improvement Program goal. The law calls Loan and Grant program as well as for every utility in the state to work toward other programs. an energy savings goal that is equivalent to 1.5 percent of annual retail energy sales.

17

Doing good in the Sharing services with community members Every day for two weeks in Great River Energy and its member April, employee groups cooperatives continually find new ways volunteered their time to help to share services that save money and Habitat for Humanity build a generate revenue. Every year, Great new home for a family in River Energy increases the information need. The home now shelters technology services it provides through a single mother and her four agreements with interested member

children and is served by a cooperatives and wholly owned

Great River Energy volunteers spent a dreary April day roofing Great River Energy member subsidiaries. a Habitat for Humanity house. In all, more than 100 employees cooperative. worked on the house, which is now home to a family of five. Rather than hire vendors, Great River For the fifth consecutive year, Energy and its member cooperatives Great River Energy was recognized as a collaborate on services ranging from member of the Keystone Program, an ongoing support to short-term projects. organization of the Minneapolis Regional These agreements save money and boost

Chamber of Commerce that recognizes the collective knowledge and experience companies that donate generously to among the cooperatives.

the community.

New equipment at Bismarck State Top honors College in North Dakota will help college for health students while securing a valuable Great River training tool for Great River Energy. In Energy’s wellness 2013, Great River Energy donated a initiatives landed new power plant training simulator to the the cooperative on college that is equipped with modern an elite list of employers: the 2014 computer controls and graphics. The new Healthiest 100 Workplaces in America. simulator replaced an existing simulator Great River Energy ranked 31st among that Great River Energy donated to the thousands of entries. This national award school in 1999. The simulator is used both recognizes that Great River Energy has for student education and to train Great achieved remarkable and sustainable River Energy employees preparing to success through a broad range of become control room operators. Great corporate wellness programs and River Energy funded the simulator’s employee wellness initiatives. development and installation, while the college houses it and provides training.

18

A North Dakota farmer tends to reclaimed cropland as a Falkirk Mine dragline works in the distance.

Mined land must Providing energy, respecting nature be returned to a The Falkirk Mine in central North Dakota After reclamation, Falkirk must manage provides almost eight million tons of coal the land for at least 10 years from the diverse productive to Great River Energy’s Coal Creek initial vegetation seeding. Farmers keep landscape – at Station power plant each year. The careful records of the yields of machinery and effort required to move reclaimed cropland so that Falkirk is least as productive the earth above the coal, and the coal able to show that the land has been and diverse as it itself, is immense. But arguably even more returned to an equal or greater state of was before mining immense is the work that comes after the productivity than it was originally. Only land has been mined. then can the land be released from started. bond, removed from the permit and Falkirk must return mined land to a turned completely over to private or diverse productive landscape – at least public land management. as productive and diverse as it was

before mining started. Before it starts Almost two-thirds of Falkirk’s total removing dirt, Falkirk conducts extensive permitted acres are used by local

surveys of the land to create an accurate farmers for agricultural production or record of the original composition grazing. Falkirk has received numerous and topography. state and national awards for its reclamation projects.

19 C ONTENTS

FINANCIAL HIGHLIGHTS...... 22

FINANCIAL DISCUSSION AND ANALYSIS...... 22

MANAGEMENT REPORT...... 26

INDEPENDENT AUDITORS’ REPORT...... 27

CONSOLIDATED BALANCE SHEETS...... 28

CONSOLIDATED STATEMENTS OF OPERATIONS...... 30

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME...... 31

CONSOLIDATED STATEMENTS OF CHANGES IN CAPITAL...... 31

CONSOLIDATED STATEMENTS OF CASH FLOWS...... 32

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS...... 33

MANAGEMENT AND BOARD OF DIRECTORS...... 56

20 . FINANCIAL REPORT 2 0 1 3

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21 Financial Highlights (DOLLARS IN MILLIONS)

2 013 2 012 Change

OPERATIONS Revenues $ 980.4 $ 921.2 $ 59.2 Purchased Power $ 196.4 $ 167.8 $ 28.6 Fuel $ 225.7 $ 217.9 $ 7.8 Other Operating Expenses $ 279.9 $ 250.4 $ 29.5 Depreciation and Amortization $ 115.6 $ 100.5 $ 15.1 Interest Expense $ 134.1 $ 143.8 $ (9.7)

Other Income $ 3.4 $ 4.5 $ (1.1) Nonutility Operations, Excluding Variable Interest Entity $ 10.7 $ 0.1 $ 10.6

Net Margin Attributable to GRE $ 42.8 $ 45.4 $ (2.6) FINANCIAL POSITION Electric Plant and Plant Held for Future Use $ 4,079.3 $ 3,994.8 $ 84.5

Utility Plant - net $ 2,743.9 $ 2,683.6 $ 60.3 Deferred Charges $ 215.9 $ 225.1 $ (9.2) Cash and Cash Equivalents $ 271.6 $ 323.1 $ (51.5) Total Assets $ 3,704.4 $ 3,689.8 $ 14.6 Long-term Obligations $ 2,605.8 $ 2,712.1 $ (106.3)

Members' Capital $ 487.7 $ 444.8 $ 42.9 Equity to Capitalization Ratio 15.4% 13.7% 1.7%

ELECTRIC REVENUE Financial Discussion and Analysis Electric revenue increased $48.4 million or 5.6 percent to

$918.0 million in 2013 from $869.6 million in 2012. Great River Energy’s 2013 financial results were very Electric revenue from member cooperatives was $835.7 impressive. Great River Energy exceeded its budgeted million during 2013, an increase of $35.4 million or 4.4 margin of $32.0 million by $10.8 million, deferred member percent from $800.3 million in 2012. The member revenue revenue of $13.8 million to offset future rates, returned a increase was due to increased member energy and power cost adjustment (PCA) credit of $10.2 million to its demand unit sales of 3.0 percent and 1.8 percent, members, improved its equity to capitalization to 15.4 respectively, compared to 2012, and a planned wholesale percent, well on the way to Great River Energy’s targeted rate increase. Member revenue was reduced for a PCA 20 percent by 2020, maintained its investment grade credit of $10.2 million and the deferral of member credit ratings, and sustained its strong liquidity. These revenue of $13.8 million under regulatory accounting. The impressive results include unbudgeted additional PCA allows Great River Energy to bill or credit differences depreciation related to Coal Creek Station and Stanton between actual and budgeted results in Midcontinent Station of $10.0 million as the estimated service lives were Independent System Operator (MISO) market activity, shortened to the year 2028. This decision affords Great River Energy flexibility as future operating strategies are developed in these changing times. The results of 2013 ELECTRIC REVENUES BILLED continue to strengthen Great River Energy’s financial Member Cooperatives/Others position and prepare the cooperative for the future. (DOLLARS IN MILLIONS)

MARGINS 900 82 69 800 76 60 Net margin attributable to Great River Energy for the year 62 836 700 801 ended December 31, 2013, was $42.8 million and includes 743 768 the net income from Blue Flint Ethanol LLC (Blue Flint) of 600 705

$10.0 million and Coal Creek Drying & Storage (CCD&S) 500 of $0.6 million. This compares to a budget of $32.0 million 400 for 2013 and actual results of $45.4 million for 2012. 300 Great River Energy’s indenture requires the maintenance of 200 a margin-for-interest (MFI) ratio of 1.1x in order to issue additional secured debt. In addition, Great River Energy’s 100 board of directors targeted a debt service coverage (DSC) 0 2009 2010 2011 2012 2013 ratio of 1.17x when setting member rates for 2013. Great River Energy’s 2013 operations produced an MFI of 1.24x NON-MEMBERS and a DSC of 1.22x. MEMBERS

22 Financial Discussion and Analysis CONTINUED purchased power, non-member revenue, and fuel. The infrastructure continues to age, operation and maintenance 2013 PCA credit was due to the strong performance of all expense will increase due to increased investment and of Great River Energy’s power plants, higher market inflationary increases. Great River Energy maintains its energy prices, and strong member energy unit sales. assets to ensure continued reliability. Great River Energy Electric revenue from non-members increased $13.0 million expensed $11.2 million in 2013 in outage costs related to or 18.8 percent to $82.3 million in 2013 from $69.3 million the CCS and Stanton 2013 scheduled major maintenance in 2012. This increase in revenue was the result of an outages. Additionally, as regional transmission projects increase in megawatt hour (MWh) sales of 12.5 percent owned by others are completed within the MISO territory, and an increase in average market energy prices for these Great River Energy’s share of these costs will increase. sales of 6.3 percent in 2013 compared to 2012. Great River Energy incurred $3.7 million of additional transmission expense related to these projects in 2013

OTHER OPERATING REVENUE compared to 2012. Great River Energy also incurred an additional $5.8 million in transmission expense to serve Other operating revenue increased $10.8 million or 20.9 member load under inter-utility transmission agreements in percent to $62.4 million in 2013 from $51.6 million in 2013 compared to 2012. 2012 due to increased transmission revenue from both the MISO market and under inter-utility transmission agreements of $9.1 million and increased revenue from 2013 EXPENSES AND MARGINS tipping fees and waste recovery at the Elk River Resource Processing Plant of $2.1 million. Interest Expense 13.5% Purchased % Power 19.7% OPERATING EXPENSES Property Tax 2.6 Total operating expenses for 2013 were $817.6 million, an Net Margin increase of $81.0 million or 11.0 percent from $736.6 Attributable to Great million in 2012. River Energy 4.3% Purchased power increased $28.6 million or 17.0 percent to Depreciation and $196.4 million in 2013 from $167.8 million in 2012. The Amortization 11.6% increase is largely due to purchasing 17.2 percent more Fuel 22.7% MWhs from the MISO market and increased energy purchases under bilateral contracts, including Genoa 3, during 2013. The average energy price paid increased 7.8 Operation and percent in 2013 compared to 2012. Great River Energy’s Maintenance 25.6% increased power purchases were primarily the result of increased member and non-member MWh sales and Depreciation and amortization increased $15.1 million or decreased generation from Coal Creek Station (CCS) and 15.0 percent to $115.6 million in 2013 from $100.5 million Stanton Station (Stanton) due to scheduled major in 2012. Great River Energy shortened the estimated maintenance outages during 2013. There were no scheduled service lives for CCS and Stanton to the year 2028, major maintenance outages during 2012. These increases beginning in July 2013, resulting in additional depreciation were partially offset by a decrease in capacity costs for of $10.0 million for 2013. Additionally, amortization Genoa 3 of $3.6 million in 2013 compared to 2012, due increased $4.0 million in 2013 compared to 2012 due to primarily to an extended maintenance outage in 2012. regulatory accounting for CapX2020 projects as Great Fuel expense increased $7.8 million or 3.6 percent to River Energy received approval from the Federal Energy $225.7 million in 2013 from $217.9 million in 2012. Fuel Regulatory Commission (FERC) for incentive-based rate expense at CCS increased $5.8 million or 3.6 percent due treatment for these projects. Under incentive-based rate

to increased mining costs per mined ton and increased treatment, Great River Energy expenses in the current year repairs and maintenance in the mining operation and coal the equivalent amount of interest capitalized during handling system. Fuel expense at the peaking plants construction for these projects and records an offsetting increased $4.6 million or 23.4 percent in 2013 compared regulatory liability that will be amortized over the useful to 2012. Peaking generation decreased 12.7 percent in life of the related asset.

2013 compared to 2012; however, the average natural OTHER INCOME (EXPENSE) gas price paid for the year increased 34.1 percent to $3.70/MMBtu in 2013 compared to $2.76/MMBtu in Interest expense – net of amounts capitalized decreased 2012. Fuel expense at Stanton decreased $3.9 million or $9.7 million or 6.8 percent to $134.1 million in 2013 from 16.0 percent in 2013 compared to 2012 due to Stanton $143.8 million in 2012. Interest incurred on Great River generating 18.2 percent fewer MWhs, primarily the result Energy’s long-term obligations decreased $5.5 million in of the 2013 scheduled major maintenance outage. 2013 compared to 2012 due to a lower average outstanding long-term obligations balance. Capitalized Operation and maintenance expense increased $27.4 million or 12.1 percent to $253.9 million in 2013 from interest increased $4.2 million in 2013 as construction work in progress increased in 2013 compared to 2012. $226.6 million in 2012. As Great River Energy’s

23 Financial Discussion and Analysis CONTINUED NONUTILITY OPERATIONS Nonutility operating revenue and expense represents the MEMBER AVERAGE RATE PER kWh operations of Blue Flint. Operating income increased Excluding WAPA

$10.1 million to $10.0 million in 2013 from $(0.1) million (MILLS PER kWh) in 2012 due to a record production year and strong crush 70 margins per gallon as a result of tight ethanol supplies in 70.4 the region in 2013. 60 68.5 64.0 66.3 Income from equity method investments primarily represents 50 60.3

Great River Energy’s share of net income from CCD&S for 40 2013 and 2012. 30 In January 2011, Great River Energy closed on a transaction 20 with North Dakota Refined Coal LLC (NDRC), and its subsidiaries for the lease and operation of Great River 10 Energy’s DryFining facility. NDRC represents a variable interest entity of Great River Energy and is consolidated in the 0 2009 2010 2011 2012 2013 financial statements. Great River Energy included in nonutility operations in the financial statements the noncontrolling interest net loss of $16.1 million and $14.5 million for the years ended December 31, 2013 and 2012, respectively, Other assets and investments decreased $6.8 million to which represents the net operating results of NDRC. $289.0 million in 2013 from $295.8 million in 2012. This decrease is primarily the result of a decrease in deferred 2013 REVENUES charges-financing related of $20.5 million to $97.3 million in 2013, which is due to annual amortization and a Non-member 8.2% decrease in bond issuance costs of $13.1 million, and the impact of a favorable market valuation of certain derivative instruments accounted for under regulatory Other 6. 3% accounting of $7.4 million. This decrease is offset by an increase in deferred charges-other of $11.2 million to % Nonoperating 0.4 $118.6 million in 2013. The increase is due to the deferral Nonutility Operations, of refined coal purchase costs associated with the Excluding Variable DryFining lease transaction of $12.0 million and the Interest Entity 1.1% deferral of scheduled major outage maintenance costs of $27.1 million, offset by a decrease in the deferred charges associated with the postretirement defined benefit pension and medical plans of $26.1 million. The deferred charges % Member 84.0 related to the DryFining lease will be recognized into

member rates commensurate with the net benefits of the MEMBER RATE transaction. The deferred charges related to the scheduled

Great River Energy’s 2013 member billed rate was 70.4 major outage maintenance are amortized over the maintenance cycle period, which is three years for CCS and mills/kilowatt hour (kWh) compared to 68.5 mills/kWh in 2012. The increase in member rate was due primarily to a planned four years for Stanton. The deferred charges related to the postretirement benefit plans adjust each year with the rate increase for 2013; however, the rate was favorably impacted by the PCA credit of $10.2 million in 2013. remeasurement of the associated benefit obligations. Current assets decreased $43.1 million to $608.6 million in BALANCE SHEET REVIEW 2013 from $651.7 million in 2012. Cash and cash Great River Energy’s total consolidated assets increased equivalents decreased $51.5 million to $271.6 million in $14.6 million to $3.7 billion in 2013. 2013 due to a planned strategy to reduce cash on hand. Other inventory, which consists of corn, ethanol, and related Utility plant - net increased $60.3 million to $2.7 billion in inventory at Blue Flint, decreased $11.6 million to $10.8 2013. Utility plant increased $190.4 million due to million in 2013 due to Blue Flint holding fewer bushels of additions related to Great River Energy’s investment in corn in inventory and at significantly lower prices in 2013 transmission projects, including CapX2020, of $140.4 compared to 2012. These decreases were offset by an million and other generation, general plant, and Falkirk increase in accounts receivable from members of $19.5 additions of $50.0 million. Additions were offset by net million to $146.0 million in 2013. This increase is due to retirements and depreciation of $130.1 million. member energy and demand unit sales increases for the Nonutility plant and equipment – net increased $4.2 million months of December and November in 2013 compared to to $62.9 million in 2013 from $58.7 million in 2012 due 2012, and the impact of the PCA in those same months as primarily to the commencement of construction activities at there were PCA charges for December and November in Dakota Spirit AgEnergy, LLC (DSA). 2013 compared to PCA credits in 2012.

24 Financial Discussion and Analysis CONCLUDED Members’ capital increased $42.8 million to $487.7 million Deferred income taxes increased $3.4 million to $26.6 in 2013 from $444.8 million in 2012, the result of the million in 2013 from $23.2 million in 2012 due primarily to 2013 net margin attributable to Great River Energy. timing differences related to utility plant depreciation and the deferral of scheduled major outage maintenance costs. Noncontrolling interest, which represents the capital attributable to NDRC, increased $18.1 million to $60.0 Current liabilities increased $14.4 million to $355.4 million million in 2013 from $41.9 million in 2012. The NDRC in 2013 from $341.0 million in 2012. Current portion of investors contributed capital of $35.0 million during 2013; long-term obligations increased $4.8 million to $127.0 however, this was offset by the planned net loss for 2013 million in 2013 due to planned debt repayment schedules of $16.1 million. and the addition of two new term notes. Notes payable to Other noncurrent liabilities decreased $22.7 million to members increased $4.4 million to $25.0 million in 2013 due to the timing of the activity within the member $72.7 million in 2013 from $95.4 million in 2012. This decrease was due primarily to the decrease in the defined investment program. Accounts payable increased $4.4 million to $68.1 million in 2013 due to timing, increased benefit plan obligations for Great River Energy and Falkirk of $33.2 million to $5.9 million in 2013, which is due to an December energy purchases, and CapX2020 related payables. Other accrued liabilities and notes payable increase in the discount rate for both plans in 2013 compared to 2012 and changes made in 2013 to benefits increased $4.7 million to $27.8 million in 2013 due primarily to timing. Derivative instruments decreased $4.1 in the Falkirk plan. This decrease was offset by an increase of $9.9 million for asset retirement obligations, of which million to $7.3 million in 2013 due to the favorable valuation of certain unsettled interest rate hedging $7.9 million was due to a change in estimate for the CCS ash disposal sites capping and reclamation liability. contracts in 2013 compared to 2012.

Regulatory liabilities increased $63.3 million to $83.9 million LIQUIDITY POSITION AND FINANCING in 2013 from $20.6 million in 2012. This increase was due Great River Energy’s year end 2013 unrestricted available primarily to the deferral of the net proceeds from the liquidity of $604.8 million was comprised of cash and cash settlement of certain interest rate hedging instruments in equivalents of $271.6 million and unused capacity on its 2013 of $36.2 million, the deferral of member revenue in existing unsecured credit facilities of $333.8 million. Great 2013 of $13.8 million, and an increase of $5.7 million in the River Energy’s unsecured credit facilities include a $600.0 deferred liability under regulatory accounting of certain million revolving credit agreement that expires in June 2017, derivative instruments with fair values recorded as assets. after the execution of a one year extension in January 2014, Long-term obligations decreased $106.3 million to $2.6 and a $30.0 million line of credit with CoBank ACB (CoBank) billion in 2013 from $2.7 billion in 2012. The decrease is that expires in October 2014. Great River Energy uses its primarily the result of classifying as current the 2014 unsecured credit facilities for general working capital and for scheduled principal payments of $122.2 million, reduced financing its construction program. Great River Energy has the borrowings on the unsecured syndicated credit facility of option to increase the revolving credit agreement to $775.0 $15.0 million, and Blue Flint’s $5.0 million payment on the million, subject to certain terms and conditions. line of credit. This decrease is offset by additional Construction borrowings on the unsecured credit facilities borrowings of $14.2 million under two term notes, of which are repaid periodically with issuances of long-term secured $11.3 million is long-term, and borrowings of $25.0 million debt under Great River Energy’s Indenture of Mortgage, by Dakota Spirit AgEnergy Finance, LLC (DSAF), a wholly Security Agreement and Financing Statement. Since Great owned subsidiary. River Energy’s 2007 prepayment of its debt under the RUS Mortgage with the issuance of the $1.3 billion 2007A

bonds, Great River Energy has issued an additional $1.345 LONG-TERM DEBT billion of secured debt.

(DOLLARS IN MILLIONS) (INTEREST RATE) Great River Energy plans to issue long-term debt during 3000 10% 2014 in an amount yet to be determined to reduce its borrowings on the revolving credit agreement. Utilizing 2,834 2500 2,684 2,774 2,733 9% existing available cash and cash equivalents, budgeted internally generated funds, and planned short-term 2,364 2000 8% borrowings under credit facilities, Great River Energy anticipates being able to fund the majority of its 1500 7% CapX2020 transmission projects and the additions and upgrades to existing generation, transmission, and other 1000 6% general plant facilities in 2014. 5.93% 5.93% 5.75% 5.53% The strong financial results of 2013 contribute toward a 500 5.50% 5% goal and plan outlined by Great River Energy’s board of

0 4% directors to continually improve the cooperative’s financial 2009 2010 2011 2012 2013 strength and prepare for the future. In management’s view, Great River Energy is well positioned to continue making Long-term Obligations, Including Current Maturities progress toward this goal. Weighted Average Interest Rate 25 Management Report

To the Board of Directors and Members of Great River Energy:

Management is responsible for the fairness and accuracy of the financial information presented in this annual report. The accompanying financial statements have been prepared in accordance with generally accepted accounting principles, using management’s best estimates and judgments where appropriate. Great River Energy maintains an internal accounting control system that provides reasonable assurance of the integrity and reliability of the financial statements and the protection of assets from loss or unauthorized use or disposition. Directors, who are not employees, make up the Finance and Audit Committee of the Board of Directors. The committee meets regularly with management and independent public accountants to review and discuss Great River Energy’s internal accounting controls and financial reports. The independent public accountants have free access to the committee and the Board of Directors, without management present, to discuss the findings of their audits.

David Saggau President and CEO Great River Energy Maple Grove, Minnesota March 18, 2014

26 Independent Auditors’ Report

To the Board of Directors of Great River Energy Maple Grove, Minnesota We have audited the accompanying consolidated financial statements of Great River Energy (GRE), which comprise the consolidated balance sheets as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, changes in capital, and cash flows for each of the three years in the period ended December 31, 2013, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of

consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of Blue Flint Ethanol LLC (Blue Flint), a wholly owned subsidiary, which statements reflect total assets constituting 1% of consolidated total assets as of December 31, 2013 and 2012, and total revenues constituting 16% and 18%, respectively, of consolidated total revenues for the years then ended. Also, we did not audit the financial statements of Blue Flint, GRE’s investment which was accounted for by use of the equity method as of December 31, 2011. GRE’s equity method investment of $23,331,000 in Blue Flint’s net assets as of December 31, 2011, and of $3,440,000 in Blue Flint’s net income for the year ended December 31, 2011, is included in the accompanying consolidated financial statements. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, in so far as it relates to the amounts included for Blue Flint, is based solely on the report of the other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to GRE’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of GRE’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GRE as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in accordance with accounting principles generally accepted in the United States of America.

Minneapolis, Minnesota March 18, 2014

27 Consolidated Balance Sheets AS OF DECEMBER 31, 2013 AND 2012 (IN THOUSANDS)

ASSETS 2013 2012 UTILITY PLANT: Electric plant $ 3,653,224 $ 3,569,607 Plant held for future use 426,068 425,156 Coal mine plant 351,486 352,789 Construction work in progress 221,242 134,028 Less accumulated depreciation and amortization (1,908,156) (1,798,030) Utility plant — net 2,743,864 2,683,550 NONUTILITY PLANT AND EQUIPMENT — Net 62,893 58,679 OTHER ASSETS AND INVESTMENTS: Restricted investments — deferred compensation 12,285 10,762 Other investments 28,223 27,716

Deferred charges — financing related 97,259 117,756

Deferred charges — other 118,632 107,393 Other long-term assets 29,045 27,477 Other long-term receivables: Members 566 2,151 Others — net of allowance for doubtful accounts of $100 for both 2013 and 2012 3,001 2,564

Total other assets and investments 289,011 295,819

CURRENT ASSETS:

Cash and cash equivalents 271,610 323,108

Accounts receivable:

Members 146,000 126,532

Others — net of allowance for doubtful accounts of $535 and $0 for 2013 and 2012, respectively 17,968 18,005 Inventories: Materials and supplies 69,702 72,680 Fuel 22,904 23,700 Other 10,833 22,435 Prepaids and other current assets 20,672 25,558 Derivative instruments 21,762 15,708 Deferred income tax benefit 27,182 23,993 Total current assets 608,633 651,719 TOTAL $ 3,704,401 $ 3,689,767

Continued

28 Consolidated Balance Sheets

LIABILITIES AND CAPITAL 2013 2012 CAPITAL: Members: Patronage capital $ 487,663 $ 444,827 Memberships 33 Total members’ capital 487,666 444,830 Noncontrolling interest 60,043 41,883 Total capital 547,709 486,713 OTHER NONCURRENT LIABILITIES 72,717 95,395 REGULATORY LIABILITIES 83,895 20,586 LONG-TERM OBLIGATIONS — Less current portion 2,605,797 2,712,106

DEFERRED COMPENSATION 12,285 10,762

DEFERRED INCOME TAXES 26,636 23,220

COMMITMENTS AND CONTINGENCIES (Notes 4, 5, and 10) CURRENT LIABILITIES: Current portion of long-term obligations 126,950 122,141 Notes payable to members 24,969 20,562 Obligations under line of credit 10,000 10,000 Accounts payable 68,057 63,636

Property and other taxes 25,228 22,673

Other accrued liabilities and notes payable 27,804 23,118

Accrued interest payable 65,056 67,432

Derivative instruments 7,298 11,423 Total current liabilities 355,362 340,985

TOTAL $ 3,704,401 $ 3,689,767

See notes to consolidated financial statements. Concluded

29 Consolidated Statements of Operations FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011 (IN THOUSANDS)

2013 2012 2011 UTILITY OPERATIONS UTILITY OPERATING REVENUE: Electric revenue $ 917,998 $ 869,619 $ 828,153 Other operating revenue 62,444 51,578 36,155 Total utility operating revenue 980,442 921,197 864,308 UTILITY OPERATING EXPENSES: Purchased power 196,423 167,780 181,322 Fuel 225,680 217,889 200,886 Operation and maintenance 253,948 226,572 212,629 Depreciation and amortization 115,600 100,463 97,979 Property and other taxes 25,968 23,872 22,775 Total utility operating expenses 817,619 736,576 715,591 UTILITY OPERATING MARGIN 162,823 184,621 148,717

OTHER INCOME (EXPENSE): Other income — net 1,897 2,128 2,040 Interest income 1,580 2,326 2,142 Interest expense — net of amounts capitalized (134,137) (143,783) (124,506)

Other expense — net (130,660) (139,329) (120,324) NET UTILITY MARGIN 32,163 45,292 28,393 NONUTILITY OPERATIONS: Operating revenue 190,603 197,210 Operating expense 180,576 197,331 Operating income (loss) 10,027 (121) - Income from equity method investments 646 200 3,142 Loss from variable interest entity (16,058) (14,539) (13,142) Net nonutility operations (5,385) (14,460) (10,000) NET MARGIN, INCLUDING NONCONTROLLING INTEREST 26,778 30,832 18,393 NONCONTROLLING INTEREST NET LOSS 16,058 14,539 13,142 NET MARGIN ATTRIBUTABLE TO GREAT RIVER ENERGY $ 42,836 $ 45,371 $ 31,535

See notes to consolidated financial statements.

30 Consolidated Statements of Comprehensive Income FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011 (IN THOUSANDS)

2013 2012 2011 NET MARGIN, INCLUDING NONCONTROLLING INTEREST $ 26,778 $ 30,832 $ 18,393 COMPREHENSIVE INCOME — Change in interest rate swap valuation — equity method investment 405 COMPREHENSIVE INCOME, INCLUDING NONCONTROLLING INTEREST 26,778 30,832 18,798 NONCONTROLLING INTEREST COMPREHENSIVE LOSS 16,058 14,539 13,142 COMPREHENSIVE INCOME ATTRIBUTABLE TO GREAT RIVER ENERGY $ 42,836 $ 45,371 $ 31,940

See notes to consolidated financial statements.

Consolidated Statements of Changes in Capital FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011 (IN THOUSANDS)

Accumulated Other Patronage Comprehensive Noncontrolling Total Capital Memberships Income (Loss) Interest Capital BALANCE — January 1, 2011 $ 367,921 $ 3 $ (405) $ - $ 367,519 Comprehensive income (loss): Net margin (loss) 31,535 (13,142) 18,393 Change in unrealized loss on interest rate swap — equity method investment 405 405 Total comprehensive income (loss) 31,535 - 405 (13,142) 18,798 Capital contributed by noncontrolling interest 105,930 105,930 Capital distributed by noncontrolling interest (13,876) (13,876) Dividends paid by noncontrolling interest (715) (715) BALANCE — December 31, 2011 399,456 3 - 78,197 477,656 Net margin (loss) and comprehensive income (loss) 45,371 (14,539) 30,832 Capital distributed by noncontrolling interest (21,016) (21,016) Dividends paid by noncontrolling interest (759) (759) BALANCE — December 31, 2012 444,827 3 - 41,883 486,713 Net margin (loss) and comprehensive income (loss) 42,836 (16,058) 26,778 Capital contributed by noncontrolling interest 34,989 34,989 Dividends paid by noncontrolling interest (771) (771) BALANCE — December 31, 2013 $ 487,663 $ 3 $ - $ 60,043 $ 547,709

See notes to consolidated financial statements.

31 Consolidated Statements of Cash Flows FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011 (IN THOUSANDS)

2013 2012 2011

CASH FLOWS FROM OPERATING ACTIVITIES: Net margin, including noncontrolling interest $ 26,778 $ 30,832 $ 18,393 Adjustments to reconcile net margin to net cash provided by operating activities: Depreciation and amortization: Charged to operating expenses 115,600 100,463 97,979 Charged to fuel expense and other accounts 30,251 16,958 18,468 Income from equity method investments (646) (200) (2,880) Patronage credits earned from investments (1,205) (906)

Deferred charges (39,075) (12,000) (15,670) Regulatory liabilities 13,750

Changes in working capital (excluding cash, investments, and borrowings):

Accounts and long-term receivables (17,538) (2,262) 4,401 Inventory and other assets 8,737 (26,690) (7,530) Accounts payable, taxes, and other accrued expenses 4,183 (9,492) (11,680) Accrued interest (2,374) (2,355) 2,966 Noncurrent liabilities (6,275) 7,772 (3,144) Net cash provided by operating activities 132,186 102,120 101,303 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (164,275) (150,745) (144,982) Proceeds from sale of property 348 374 378 Purchase transactions and investment in equity method investments — net of cash acquired of $24,174 in 2012 5,660 (102) Redemption of patronage capital from investments 698 449 Purchases of investments (61,230)

Proceeds from maturity of investments 60,000 896 Net cash used in investing activities (163,229) (84,262) (205,040)

CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from issuance of long-term obligations 315,205 120,000 180,475

Repayments of long-term obligations (416,726) (127,141) (98,201)

Proceeds from interest rate hedging instruments settlement 42,915

Costs of new debt issuances, leases, and interest rate hedging instruments (474) (6,445) (10,791)

Borrowings on line of credit — net 10,000

Notes received from (paid to) members — net 4,407 4,975 (5,258)

Capital contributed by noncontrolling interest 34,989 105,930

Capital distributed by noncontrolling interest (21,016) (13,876)

Dividends paid by noncontrolling interest (771) (759) (715) Net cash (used in) provided by financing activities (20,455) (20,386) 157,564 NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (51,498) (2,528) 53,827

CASH AND CASH EQUIVALENTS — Beginning of year 323,108 325,636 271,809

CASH AND CASH EQUIVALENTS — End of year $ 271,610 $ 323,108 $ 325,636

See notes to consolidated financial statements.

32 Notes to Consolidated Financial Statements AS OF DECEMBER 31, 2013 AND 2012, AND FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011

1. ORGANIZATION ORGANIZATION — Great River Energy (GRE) is a Minnesota electric generation and transmission cooperative corporation providing wholesale electric service to member distribution cooperatives engaged in the retail sale of electricity to member consumers in Minnesota and a small section of Wisconsin. This service is provided in accordance with the terms of the power purchase and transmission service contracts between GRE and the members. These contracts have expiration dates of December 31, 2045, and December 31, 2050, respectively. BASIS OF ACCOUNTING — The consolidated financial statements are prepared on the accrual basis of accounting and include the accounts of GRE, as well as the following entities:

Years Entity Relationship Consolidated

The Falkirk Mining Company (Falkirk) Variable interest entity 2013, 2012, 2011 North Dakota Refined Coal LLC (NDRC) Variable interest entity 2013, 2012, 2011

Midwest AgEnergy Group, LLC (MAG) Wholly owned subsidiary 2013

Blue Flint Ethanol LLC (Blue Flint) Wholly owned subsidiary 2013, 2012 Dakota Spirit AgEnergy Finance, LLC (DSAF) Wholly owned subsidiary 2013 Dakota Spirit AgEnergy, LLC (DSA) Wholly owned subsidiary 2013

The consolidation of NDRC also includes NDRC’s wholly owned subsidiaries, North Dakota Refined Coal Project Company A LLC and North Dakota Refined Coal Project Company B LLC. All significant intercompany balances and transactions have been eliminated in consolidation, except for the steam sales between GRE and Blue Flint discussed within Note 1. FALKIRK — GRE has an agreement with Falkirk for the Assets and liabilities included in the consolidated balance development and operation of a lignite coal mine. Falkirk sheets as of December 31, 2013 and 2012, after is the coal supplier for the Coal Creek Station (CCS), intercompany eliminations, are as follows (in thousands): GRE’s steam-generating facility located near 2013 2012 Underwood, North Dakota. GRE is required to provide financing for all costs associated with the mine Coal mine plant $ 297,855 $ 299,158 development and operation. Accounting principles Construction work in progress 1,582 1,303 generally accepted in the United States of America (“generally accepted accounting principles”) require GRE Accumulated depreciation and amortization (158,152) (145,710) to consolidate its financial statements with Falkirk since Deferred charges 10,838 31,680 Falkirk qualifies as a variable interest entity for which GRE is the primary beneficiary. The coal purchase price Other long-term assets 6,784 7,436

includes all costs incurred by Falkirk for development and Fuel inventory 5,175 5,404

operation of the mine, including Falkirk’s interest expense Materials and supplies inventory 21,037 19,284

of $3.5 million, $3.9 million, and $4.1 million in 2013, Deferred income tax benefit 546 772 2012, and 2011, respectively; income tax expense of Other current assets 323 1,490 $2.7 million, $3.0 million, and $2.4 million in 2013, Other noncurrent liabilities 26,150 47,671 2012, and 2011, respectively; and net income of $12.0 million, $11.6 million, and $11.3 million in 2013, 2012, Long-term obligations 63,627 78,393

and 2011, respectively, all of which are part of the Current liabilities 25,791 26,623 contract cost of coal purchased under the coal sales agreement. Accordingly, the net effect of consolidating Falkirk is a wholly owned subsidiary of the North American the income statement of Falkirk had no impact on GRE’s Coal Corporation (NACC), which is a wholly owned margin for the years ended December 31, 2013, 2012, subsidiary of NACCO Industries, Inc. Falkirk is principally and 2011. engaged in lignite mining through the operation of a surface mine in North Dakota.

33 Notes to Consolidated Financial Statements CONTINUED

NDRC — Beginning on January 21, 2011, GRE has an JPM Capital Corporation and WM Refined Coal, LLC agreement with NDRC, or its wholly owned subsidiaries, for hold a 55% and 45% membership interest, respectively, the lease and operation of the DryFining facility at CCS. in NDRC. NoDak is a wholly owned subsidiary of TRU NDRC purchases coal from GRE under fixed pricing, Global Energy Services LLC, a wholly owned subsidiary refines the coal in the DryFining facility, and sells the of NACC. refined coal to GRE under fixed pricing. GRE provides BLUE FLINT — Blue Flint operates an ethanol biorefinery certain other services to NDRC under fee arrangements. facility located in Underwood, North Dakota. Blue Flint has The lease and related agreements have a 16-year term; a production capacity of approximately 65 million gallons however, included in the participation agreement is a of undenatured ethanol per year. Blue Flint is a dry-mill purchase option to buy out the remaining term of the production facility that produces and sells ethanol, dry and transaction on January 31, 2020. Generally accepted modified distillers grain, and distillers oil. accounting principles require GRE to consolidate its financial statements with NDRC, since NDRC qualifies as a Prior to 2012, GRE owned 49% of Blue Flint and variable interest entity for which GRE is the primary accounted for Blue Flint as an equity method investment. beneficiary. NDRC entered into an operating and On January 1, 2012, GRE purchased the remaining 51% maintenance agreement with NoDak Energy Services LLC ownership interest in Blue Flint from HES Ethanol Holdings, (“NoDak”) to perform the day-to-day operation and LLC for a cash purchase price of $18.3 million. As GRE is subject to regulatory accounting, the fair value of GRE’s maintenance of the DryFining facility. NoDak qualifies as a variable interest entity for which NDRC is the primary 49% equity interest in Blue Flint was determined to be beneficiary. As a result, GRE is also consolidating NoDak net book value, as of January 1, 2012, of $23.9 million. as part of NDRC. The utility fuel operating expense in the The transaction price of $18.3 million was determined to consolidated statements of operations includes a net be fair value for the 51% ownership interest using both benefit to GRE of $11.4 million, $10.1 million and $9.4 the market and income approaches. GRE did not million for the years ended December 31, 2013, 2012, recognize any gain or loss related to this transaction. and 2011, respectively, related to this transaction. This The recognized amounts of identifiable assets acquired includes the revenue from the lease and other agreements and liabilities assumed at January 1, 2012, are as partially offset by the costs incurred for the purchase of follows (in thousands): refined coal from NDRC. The net loss incurred by NDRC of Cash $ 24,174 $16.1 million, $14.5 million, and $13.1 million for the years ended December 31, 2013, 2012, and 2011, Accounts receivable — net of allowance for respectively, is reported as nonutility operations in the doubtful accounts of $0 5,133 consolidated statements of operations. Inventory 14,415

The agreements include various operational metrics, such Other financial assets 3,674 as minimum requirements on the tons of refined coal Plant and equipment 61,722 purchased by GRE and the achievement of qualified Financial liabilities (66,938) emission reductions. In the event that the operational Total identifiable net assets $ 42,180 metrics are not met over the life of the transaction, GRE may be required to pay specified amounts to NDRC at transaction termination. No liability has been recorded by The pro forma net margin attributable to GRE would GRE in the consolidated financial statements related to have been $35.9 million for the year ended December these operational metrics as of December 31, 2013 and 31, 2011, had Blue Flint been wholly owned for all years 2012. presented. Blue Flint’s operating revenue was $187.3 million for the year ended December 31, 2011, and Assets and liabilities included in the consolidated balance would have been reported as nonutility operations had sheets as of December 31, 2013 and 2012, after Blue Flint been wholly owned for all years presented. intercompany eliminations, are as follows (in thousands): Blue Flint purchases steam and water under a long-term 2013 2012 contract from CCS for use in the production of ethanol Cash $ 4,016 $ 680 and related products. Steam and water purchases were $5.6 million and $5.5 million for the years ended Prepaids 73 70 December 31, 2013 and 2012, respectively. The sale of Current liabilities 234 232 steam and water by CCS is recorded as utility other operating revenue and the purchase by Blue Flint is recorded as nonutility operating expense. This transaction was not eliminated in consolidation for 2013 and 2012.

34 Notes to Consolidated Financial Statements CONTINUED

Utility net margin and nonutility operating income (loss) as of December 31, 2013 and 2012, would be as follows had this transaction been eliminated (in thousands):

2013 2012

As With As With Presented Elimination Presented Elimination

Net utility margin $ 32,163 $ 26,564 $ 45,292 $ 39,792

Nonutility operating income (loss) $ 10,027 $ 15,626 $ (121) $ 5,379 Total $ 42,190 $ 42,190 $ 45,171 $ 45,171

The equity method investment activity for Blue Flint for the year ended December 31, 2011, is as follows (in thousands):

2011

Beginning equity investment balance $ 19,486 GRE’s share of Blue Flint’s income 3,440 GRE’s share of Blue Flint’s other comprehensive income 405

Ending equity investment balance $ 23,331

GRE’s share of Blue Flint’s accumulated other comprehensive income relates to an interest rate swap agreement

designated as a cash flow hedge, which Blue Flint recorded at fair value. GRE recognized $4.6 million in steam sales to

Blue Flint and $1.2 million related to Blue Flint’s use of CCS infrastructure for the year ended December 31, 2011.

During 2013, GRE transferred its ownership interest in Blue Flint to another GRE wholly owned subsidiary, MAG. MAG — MAG has two wholly owned subsidiaries, Blue Flint and DSAF, as of December 31, 2013. DSAF’s wholly owned subsidiary, DSA, began construction in 2013 of a biorefinery facility located near Jamestown, North Dakota. DSA will be a dry-mill production facility that produces and sells ethanol, dry and modified distillers grain, and distillers oil, and it will have a production capacity of approximately 65 million gallons of undenatured ethanol

per year.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

REGULATORY ACCOUNTING — GRE operations follow regulatory accounting provisions as provided in generally accepted accounting principles and the consolidated financial statements contain various items reported under these regulatory provisions. As the board of directors sets rates on a cost-of-service basis, GRE follows generally accepted accounting principles related to the effects of certain types of regulation, which provides for the reporting of assets

and liabilities consistent with the economic effect of the rate structure. As such, regulatory assets are recorded to reflect probable future revenues associated with certain costs that are expected to be recovered from customers through the rate-making process. Regulatory liabilities are recorded to reflect probable future reductions in revenues associated with amounts that are expected to be credited to customers through the rate-making process. For further information see Note 11. CASH AND CASH EQUIVALENTS — Cash equivalents include all highly liquid investments with original maturities of

three months or less (e.g., money market funds). Certain cash and cash equivalents are classified as investments when they relate to trust funds held for long-term purposes.

35 Notes to Consolidated Financial Statements CONTINUED

SUPPLEMENTAL CASH FLOW INFORMATION — Supplemental cash flow information for the years ended December 31, 2013, 2012, and 2011, is as follows (in thousands): 2013 2012 2011

Supplemental disclosure of cash flow information: Cash paid for interest — net of amounts capitalized $ 144,429 $ 154,320 $ 126,521 Cash paid for taxes — Falkirk $ 1,759 $ 3,642 $ 3,061

Noncash investing and financing activities: Utility plant acquisitions included in accounts payable $ 8,375 $ 6,994 $ 8,503 Utility plant acquired under capital lease $ 1,264 $ 19,653 $ 5,294

Interest on borrowed funds in the amount of $8.4 million, $4.1 million, and $26.5 million was capitalized in 2013, 2012, and 2011, respectively, and these amounts are excluded from the cash payments for interest noted above.

INVENTORIES — Fuel inventory is carried at average and the prevailing short-term investment rates for other cost and includes coal, lime, oil, and gas used for electric than borrowed funds. Repairs and maintenance are generation. Other inventory represents corn, chemical, charged to operations as incurred. When generation and ethanol, and distillers grain inventory held at Blue Flint. transmission assets are retired, sold, or otherwise Corn and chemical inventory is stated at the lower of cost disposed of, the original cost, plus the cost of removal, (on the first-in, first-out method) or market. Ethanol and less salvage, is charged to accumulated depreciation and distillers grain inventory is stated at the lower of cost the corresponding gain or loss is amortized over the

(average monthly cost) or market. Materials and supplies remaining life of the plant. Included in accumulated inventory is stated at the lower of average cost or depreciation are retired assets totaling $(42.8) million market. and $(44.2) million at December 31, 2013 and 2012, respectively, that will continue to be amortized. Also Emission allowances are also accounted for as fuel included in accumulated depreciation are nonlegal or inventory and recorded at the lower of cost or market. The U.S. Environmental Protection Agency has noncontractual costs of removal components in the amount of $48.0 million and $45.5 million for 2013 and 2012, requirements limiting the amount of sulfur dioxide that can be emitted from GRE-owned power plants. Under respectively. When other property assets are retired or sold, the cost and related accumulated depreciation are these requirements, GRE was allotted one emission allowance per ton of sulfur dioxide emissions based upon eliminated and any gain or loss is reflected in other income (expense). historic emission levels. GRE had approximately 196,000 and 142,000 allowances in inventory and available-for- PLANT HELD FOR FUTURE USE — Plant held for future sale at December 31, 2013 and 2012, respectively, with use represents the costs associated with Spiritwood a recorded cost of $0 for both years. Station, the related coal load out facility at CCS, and Renewable energy credits (RECs) are either purchased or land held for future use. The plant costs include materials, acquired in the course of generation, or purchased as a contract and direct labor, overhead, and interest during result of meeting load obligations, and are recorded as construction. Construction activities at Spiritwood Station fuel inventory at cost. GRE had approximately 4.5 million have ceased. The plant is not considered substantially and 3.5 million RECs in fuel inventory and available-for- complete in its current state and is not being depreciated. sale at December 31, 2013 and 2012, respectively, with Spiritwood Station will be completed, placed in service, a recorded cost of $0.5 million and $0, respectively. and fully included in member rates in November 2014.

UTILITY PLANT — Utility plant is stated at original cost, DEPRECIATION AND AMORTIZATION — Depreciation which includes materials, contract and direct labor, for financial reporting purposes is provided based upon overhead, allowance for funds used for construction, and the straight-line method at rates designed to amortize interest during construction. Interest charged to the original cost of properties over their estimated construction on borrowed funds and allowance for funds service lives. During 2013, GRE revised the estimated used for construction (other than borrowed funds) are service lives for CCS and Stanton Station (“Stanton”) to included as a component of utility plant cost and credited be 2028. These plants, along with any future additions, to interest expense and interest income, respectively. The will be fully depreciated by the end of 2028. The rates applied reflect the actual rates for borrowed funds effective depreciation rate was 2.9%, 2.6%, and 2.6% for 2013, 2012, and 2011, respectively. The range of

36 Notes to Consolidated Financial Statements CONTINUED

useful lives for utility plant is three to 50 years. Coal mine MEMBERS’ PATRONAGE CAPITAL — Revenues in excess equipment is amortized using a straight-line method over of current-period costs (net margin attributable to GRE) the estimated useful lives. Amortization of coal lands and in any year are designated as assignable margins. These leaseholds is calculated on the units-of-production method assignable margins are considered capital furnished by based upon estimated recoverable tonnages and is the members and are credited to the members’ individual included in utility fuel expense in the consolidated accounts. Assignable margins are held by GRE until they statements of operations. Amortization expense also are retired and returned, without interest, at the includes the amortization of bond discounts, accretion discretion of the board of directors and subject to long- expense related to asset retirement obligations, and the term obligation agreement restrictions (see Note 5). amortization of deferred charges, except as described in Retained assignable margins are designated as Note 11. patronage capital in the consolidated balance sheets. NONUTILITY PLANT AND EQUIPMENT — NET — USE OF ESTIMATES — The preparation of consolidated Nonutility plant and equipment represents Blue Flint plant financial statements in conformity with generally and equipment and DSA construction work in progress. accepted accounting principles requires management to Blue Flint plant and equipment is recorded at fair value, make estimates and assumptions that affect the reported as determined as of the acquisition date of the remaining amounts of assets and liabilities and disclosure of 51% ownership interest. Depreciation for financial contingent assets and liabilities at the date of the reporting purposes is provided based upon the straight- consolidated financial statements and the reported line method. The range of useful lives for nonutility plant amounts of revenues and expenses during the reporting and equipment is three to 40 years. period. The significant estimates in the consolidated

A summary of nonutility plant and equipment as of financial statements relate to key inputs to actuarial calculations of defined benefit obligations, compensation December 31, 2013 and 2012, is as follows (in thousands): and benefit accruals, asset retirement obligation liabilities, accrued property and other taxes, useful lives 2013 2012 of utility and nonutility plant, recoverability of deferred

Land improvements $ 7,572 $ 7,556 tax assets, the fair value of Blue Flint assets and liabilities at the acquisition date, and contingencies and other Buildings and improvements 14,661 14,640 reserves. Actual results could differ from those estimates. Equipment and other 40,463 39,932 REVENUE RECOGNITION — Electric revenue is Construction work in progress 7,393 126 recognized when energy is delivered to GRE’s members Less accumulated depreciation (7,196) (3,575) or to other non-member organizations. The GRE rate

$ 62,893 $ 58,679 schedule includes a power cost adjustment that allows for increases or decreases in member power billings based RECOVERABILITY OF LONG-LIVED ASSETS — GRE upon actual power costs compared to plan. For 2013 reviews its long-lived assets whenever events or changes and 2012, the power cost adjustments were credits to in circumstances indicate the carrying value of the assets GRE members of $10.2 million and $5.6 million, may not be recoverable. GRE determines potential respectively. For 2011, the power cost adjustment was a impairment by comparing the carrying value of the asset charge of $17.3 million. Credits or charges are recorded with the net cash flows expected to be provided by the as a decrease or increase, respectively, in electric operating activities of the business or related products. revenue in the consolidated statements of operations. In Should the sum of the expected cash flows be less than 2013, GRE deferred the recognition of $13.8 million of the carrying values, GRE would determine whether an member electric revenue under regulatory accounting impairment loss should be recognized. No impairment (see Note 11). losses have been identified in the consolidated financial OTHER OPERATING REVENUE — Other operating statements. revenue includes revenue related to the processing plant INCOME TAXES — GRE accounts for income taxes using that transforms municipal solid waste into refuse-derived the liability method. Under this method, deferred income fuel and the burning of that fuel at the Elk River Energy taxes are recognized for temporary differences between Recovery Station, revenue received from other utilities the tax and financial reporting bases of assets and related to providing transmission service under various liabilities using enacted tax rates in effect for the year in integrated transmission agreements, and revenue from which the differences are expected to reverse. the sale of utility plant by-products, such as steam and fly ash. Other operating revenue is recorded as services are provided.

37 Notes to Consolidated Financial Statements CONTINUED

NONUTILITY OPERATIONS — Nonutility operating The schedule of GRE and Blue Flint future minimum lease revenue and expense represents Blue Flint operations for payments as of December 31, 2013, is as follows (in the years ended December 31, 2013 and 2012. thousands): Revenue from the production of ethanol and related products is recorded at the time the title of the goods Years Ending Blue and all risk of ownership transfers to customers and December 31 Flint GRE settlement price is realizable. Transfer of ownership 2014 $ 2,770 $ 750 generally occurs when the product is shipped and risk of 2015 2,770 504 loss is assumed by the customer. 2016 891 424 SUBSEQUENT EVENTS — GRE has considered 2017 74 358 subsequent events for recognition or disclosure through 2018 331 March 18, 2014, the date the consolidated financial Thereafter 282 statements were available to be issued. $ 6,505 $ 2,649 3. RECENTLY ISSUED ACCOUNTING STANDARDS CAPITAL LEASES — GRE is the lessee of a dragline used In December 2011, the Financial Accounting Standards in the Falkirk coal mining operations. The original lease agreement was due to expire in 2005. GRE amended Board (FASB) issued guidance on the offsetting of assets and liabilities, which is effective for GRE in 2013. The this lease in 2001 to extend the term to 2015, at which time GRE will purchase the asset for $1. The gross guidance requires additional disclosures regarding offsetting arrangements of balance sheet derivatives to amount of this lease was $48.3 million at December 31, enable financial statement users to understand the effect 2013, with accumulated amortization of $46.7 million and $45.6 million as of December 31, 2013 and 2012, of these arrangements on a company’s financial position. The adoption of this standard did not have a material respectively. GRE has the right of first refusal should a impact on GRE’s consolidated financial statement disposition of property occur. The principal and interest disclosures. payments were $1.6 million for both 2013 and 2012.

In December 2013, the FASB issued Accounting GRE entered into an agreement as the lessee of railroad Standards Update No. 2013-12, Definition of a Public cars to be used in the future operation of the Spiritwood Business Entity. GRE is currently in the process of Station generation facility. The lease expires in 2020. evaluating this guidance; however, GRE believes it meets The gross amount of the lease was $7.6 million at the definition of a public business entity due to the December 31, 2013, with accumulated amortization of issuance of debt securities that are traded on an over- $2.7 million and $1.9 million at December 31, 2013 and the-counter market. 2012, respectively. The principal and interest payments were $1.1 million for both 2013 and 2012.

4. LEASING TRANSACTIONS Falkirk has also leased certain equipment that is used in OPERATING LEASES — GRE is the lessee on various mining operations. The gross amount of these leases was operating leases for equipment used in its operations. $131.1 million and $137.1 million and the accumulated These transactions are governed by the terms of various amortization was $54.1 million and $46.3 million as of December 31, 2013 and 2012, respectively. These master lease agreements. The lease term of each leased amounts are recorded in coal mine plant and item is determined at the time it is added to its respective master lease. Original lease terms ranged from 60 to 96 accumulated depreciation and amortization in the consolidated balance sheets. months. Falkirk is the lessee on various short-term operating leases for equipment. Blue Flint is the lessee on operating leases for railroad cars and other equipment, with terms expiring at various times through 2017. Lease expense was $4.0 million, $4.7 million, and $2.1 million in 2013, 2012, and 2011, respectively.

38 Notes to Consolidated Financial Statements CONTINUED

The schedule of future minimum lease payments for GRE The current and long-term portions of the capital lease and Falkirk leases as of December 31, 2013, is as obligations are included in current portion of long-term follows (in thousands): obligations and long-term obligations in the consolidated balance sheets (see Note 5). Years Ending December 31 Falkirk GRE 2014 $ 17,698 $ 3,456 2015 19,196 1,856 2016 16,213 1,056 2017 12,590 1,056 2018 10,116 1,056 Thereafter 10,865 1,320

Total minimum lease payments 86,678 9,800 Amounts representing interest (8,259) (1,485) Present value of minimum lease payments 78,419 8,315 Current maturities (14,792) (2,896)

Long-term capital lease obligations — net $ 63,627 $ 5,419

5. LONG-TERM OBLIGATIONS

The consolidated long-term obligations as of December 31, 2013 and 2012, are as follows (in thousands):

2013 2012

First Mortgage Bonds, Series 2007A, 5.829%, due 2014–2017 $ 200,300 $ 252,900 First Mortgage Bonds, Series 2007A, 6.254%, due 2018–2038 739,100 739,100 First Mortgage Bonds, Series 2008A, 7.233%, due 2014–2038 366,816 375,156

First Mortgage Bonds, Series 2008B, 3.0999%, due 2014–2023 16,667 18,333 First Mortgage Notes, Series 2009A, 5.0% to 7.15%, due 2014–2024 106,800 120,800 First Mortgage Bonds, Series 2009B, 5.81% to 6.94%, due 2014–2031 380,000 390,000 First Mortgage Note, Series 2010A, 4.875%, due 2026 23,000 23,000 First Mortgage Note, Series 2010B, 5.15%, due 2040 50,000 50,000 First Mortgage Note, Series 2010C, 3.5%, due 2038 33,000 33,000

First Mortgage Bonds, Series 2010D, 4.478%, due 2014–2030 382,000 395,500 Syndicated Credit Facility, National Rural Utilities Cooperative Finance Corp, 1.42% at December 31, 2013, due 2016 285,000 300,000 Department of Energy, 0.00%, due 2014–2028, 5.2% to 6.1% imputed interest 6,463 6,932 Term Note, LIBOR plus 1.375%, 1.545% at December 31, 2013, due 2014–2019 9,000

Term Note, 2.35%, due 2014–2019 5,205

Capitalized lease obligations, mining equipment, ends 2015, 6.3% imputed interest 2,962 4,310

Capitalized lease obligations, Spiritwood coal cars, ends 2020, 6.9% imputed interest 5,353 6,016 Capitalized lease obligations, Falkirk Mine, 1.2% to 5.9% imputed interest 78,419 93,314

Term Note, Blue Flint, 5.8%, due 2014–2021 14,769 16,615

Term Note, Blue Flint, LIBOR plus 3.75%, 3.92% at December 31, 2013, due 2014–2021 13,898 15,652 Revolving Line of Credit, Blue Flint, LIBOR plus 4%, due 2016 5,600 Term Note, DSAF, EB-5 Program, 7%, due 2019 25,000 Other — at various rates and maturities 3,581 3,825 Less unamortized bond discount (14,586) (15,806) 2,732,747 2,834,247 Current maturities (126,950) (122,141) Long-term obligations — net $ 2,605,797 $ 2,712,106

39 Notes to Consolidated Financial Statements CONTINUED

GRE issues secured debt under an Indenture of GRE is subject to a number of customary covenants under Mortgage, Security Agreement, and Financing Statement the Indenture, other debt agreements, and the revolving (“Indenture”). The Indenture requires GRE to establish and credit facility. collect rates reasonably expected to yield a specified Blue Flint’s revolving line of credit has a limit of $14.0 margins-for-interest level. Under the Indenture, GRE has million. Blue Flint also has a seasonal line of credit for limitations on the retirement of patronage capital if, after $10.0 million that expires July 2014. At December 31, the distribution, an event of default would exist or GRE’s 2013 and 2012, the outstanding balance on this facility members’ capital would be less than 20% of total long- was $0 for both years. term debt and members’ capital. Substantially all of the tangible assets of GRE and the power purchase and Substantially all of the assets of Blue Flint are pledged transmission service contracts with the members (see as security under the Blue Flint Term Notes. Blue Flint is Note 1) are pledged as security under the Indenture. subject to a number of restrictive covenants under its debt agreements. The First Mortgage Note, Series 2010C (“Series 2010C Note”) bears an initial fixed interest rate (3.5%) through DSAF’s term note is collateralized by a subordinated the initial term rate period, which ends June 30, 2015. security interest in substantially all of the assets of DSA. After the initial term rate period, the Series 2010C Note Future maturities on long-term obligations as of continues in term rate mode. During the term rate mode, December 31, 2013, are as follows (in thousands): a fixed interest rate is determined periodically by the remarketing agent, as described in the agreement, for an Years Ending interest period of at least 180 days. After the initial term December 31 rate period, GRE has the option, subject to provisions in 2014 $ 126,950 the agreement, to effect a change in mode for all or any 2015 125,244 portion of the Series 2010C Note from term rate mode 2016 412,218 to another form of mode, such as fixed rate, auction rate, daily rate, weekly rate, or other defined rate. After the 2017 125,467 initial term rate period, if the Series 2010C Note is 2018 120,516 Thereafter 1,822,352 subject to remarketing and the remarketing proceeds are insufficient, GRE will be required to purchase all or a $ 2,732,747 portion of the Series 2010C Note. The Series 2010C Note is not supported by a dedicated liquidity facility. GRE has a $600.0 million unsecured five-year revolving 6. INVESTMENTS credit facility for which National Rural Utilities GRE’s investments as of December 31, 2013 and 2012, Cooperative Finance Corporation (CFC) is the are as follows (in thousands): administrative agent. This facility was renewed in 2011 and expires on June 6, 2016. This facility can be 2013 2012 increased, at GRE’s option, to $775.0 million subject to Other investments: certain terms and conditions. At December 31, 2013 and Capital term certificates — CFC $ 19,644 $ 19,644 2012, the outstanding balance of this facility was Cooperative investment patronage allocations 8,579 8,072 $285.0 million and $300.0 million, respectively. These amounts are recorded in long-term obligations in the Total other investments 28,223 27,716 consolidated balance sheets. GRE also has an unsecured Restricted investments — investments for line of credit facility with CoBank ACB (“CoBank”) for deferred compensation 12,285 10,762 $30.0 million. This facility’s terms and conditions are $ 40,508 $ 38,478 renewable annually, and the principal balance must be paid in full within one business day of expiration, unless unilaterally extended by CoBank. This facility expires on October 31, 2014. At December 31, 2013 and 2012, the outstanding balance of this facility was $10.0 million and $10.0 million, respectively.

40 Notes to Consolidated Financial Statements CONTINUED

The capital term certificates bear interest ranging from 5% to 7.5% and a portion of them are required under borrowing arrangements with CFC. At December 31, 2013, GRE had no commitments to purchase additional capital term certificates from CFC. Capital term certificates are classified as held to maturity and reported at amortized cost using the specific identification method. GRE’s cooperative investment patronage allocations are reported at cost, plus allocated equities.

GRE’s investments held for deferred compensation are reported at fair value.

The investments reported at amortized cost at December 31, 2013 and 2012, are as follows (in thousands):

Gross Amortized Unrealized Unrealized Fair 2013 Cost Gains Losses Value Long-term investments — held-to-maturity securities — capital term certificates $ 19,644 $ - $ - $ 19,644

2012

Long-term investments — held-to-maturity

securities — capital term certificates $ 19,644 $ - $ - $ 19,644

Maturities on investments reported at amortized cost as of December 31, 2013, are as follows (in thousands):

One to five years $ -

Five to 10 years Greater than 10 years 19,644 $ 19,644

Interest income received on all investments was $1.6 million, $2.3 million, and $2.1 million in 2013, 2012, and 2011, respectively. This income is recorded in interest income in the consolidated statements of operations.

7. DERIVATIVE INSTRUMENTS contract inception and it is reported as “Deferred As part of its risk management program, GRE may charges — financing related” in the consolidated periodically use interest rate swaps and interest rate balance sheet at December 31, 2012. swaptions to manage market exposures. Terms of the During 2013, GRE terminated certain interest rates swap and swaption agreements are structured to match swaps and the swaption as these instruments were the terms of the risk being managed and are generally considered less effective hedges in the management of held to maturity. Marked to market gains and losses interest rate exposure due to delays in the anticipated related to the interest rate swaps and swaptions are timing of forecasted debt issuances. The proceeds from deferred as regulatory assets or liabilities under the termination of these instruments, less fees and the generally accepted accounting principles and continue to swaption premium, of $36.2 million are deferred as a be deferred until the related debt transaction is regulatory liability. As the termination of these complete. At that time, the interest rate swaps are settled instruments did not coincide with a related debt issuance, and any gains and losses are amortized to the income the net proceeds will be amortized to the income statement over the term of the related debt issuance. statement under regulatory accounting as determined by the board of directors. During 2012, GRE entered into an interest rate swaption that gave GRE the right, but not the obligation, to enter GRE is exposed to credit risk as a result of entering into into a swap in which GRE would pay a fixed rate and these interest rate hedging agreements. However, as of receive a floating rate. GRE paid a swaption premium at December 31, 2013, all of the counterparties with

41 Notes to Consolidated Financial Statements CONTINUED

transaction amounts outstanding under GRE’s hedging Blue Flint enters into derivative transactions to hedge its program are rated investment grade by the major rating exposure to commodity price fluctuations. In connection agencies. The contractual agreements contain provisions with the execution of forward commodity contracts, Blue that could require GRE or the counterparty to post Flint normally elects to create a hedging relationship by collateral or credit support. No amounts have been executing an exchange-traded futures contract as an posted by GRE or the counterparties as of December 31, offsetting position. In this situation, the forward 2013 and 2012. commodity contract is valued at market price until delivery is made against the contract. Blue Flint does not See additional information regarding the fair value of these instruments in Note 8 and amounts recorded in enter into derivative transactions for trading purposes. deferred charges and regulatory liabilities in Note 11. Blue Flint related derivative gains (losses) included in the GRE enters into contracts for the purchase and sale of consolidated statements of operations for the years commodities for use in its business operations. Generally ended December 31, 2013 and 2012, are as follows (in accepted accounting principles require an evaluation of thousands): these contracts to determine whether the contracts are 2013 2012 derivatives. Certain contracts that meet the definition of a Realized and unrealized gains (losses) derivative may be exempted from derivative accounting recognized from undesignated hedges: as normal purchases or normal sales. GRE evaluates all of its contracts at inception to determine if they are Nonutility operating revenue $ (9,126) $ 956 derivatives and if they meet the normal purchases and Nonutility operating expenses 2,348 (5,390)

normal sales designation requirements. All of the Blue Flint is exposed to credit and market risk as a result contracts for the purchase and sale of commodities used of entering into these contracts. Blue Flint manages the in business operations, with a few limited exceptions, credit risk by entering into transactions with high-quality qualify for a normal purchases or normal sales counterparties. Futures contracts entered into by Blue Flint designation. The contracts that do not qualify for a are governed by an International Swap Dealers normal purchases or normal sales designation are Association Master Agreement. Blue Flint manages recorded at fair value and the gains or losses are market risk associated with commodity-price contracts by deferred as regulatory assets or liabilities. See establishing and monitoring parameters that limit the additional information regarding the fair value of these types and degree of market risk that may be derivatives in Note 8. undertaken. Actual results could materially differ based on the changes in commodity prices.

The location and fair value of GRE’s and Blue Flint’s derivative instruments in the consolidated balance sheets as of December 31, 2013 and 2012, are as follows (in thousands):

Balance Sheet Location 2013 2012 Derivatives in an asset position, none of which are designated as hedging instruments: Interest rate contracts Derivative instruments $ 18,653 $ 12,954 Commodity contracts Derivative instruments 3,109 2,754 Total derivative instrument assets $ 21,762 $ 15,708 Derivatives in a liability position, none of which are designated as hedging instruments: Interest rate contracts Derivative instruments $ 2,227 $ 9,560

Commodity contracts Derivative instruments 5,071 1,863 Total derivative instrument liabilities $ 7,298 $ 11,423

42 Notes to Consolidated Financial Statements CONTINUED

8. FAIR VALUE OF FINANCIAL INSTRUMENTS Generally accepted accounting principles establish a framework for measuring fair value by creating a hierarchy for observable independent market inputs and unobservable market assumptions, and provides for required disclosures about fair value measurements. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that could be realized in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value.

A description of the inputs used in the valuation of assets and liabilities are as follows:

Level 1 — Inputs represent unadjusted quoted prices for identical assets or liabilities exchanged in active markets. Level 2 — Inputs include directly or indirectly observable inputs other than Level 1 inputs, such as quoted prices for similar assets or liabilities exchanged in active or inactive markets; quoted prices for identical assets or liabilities exchanged in inactive markets; and other inputs that are considered in fair value determinations of the assets or liabilities. Level 3 — Inputs include unobservable inputs used in the measurement of assets and liabilities. Management is required to use its own assumptions regarding unobservable inputs because there is little, if any, market activity in the assets or liabilities or related observable inputs that can be corroborated at the measurement date.

Assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. GRE’s policy is to recognize significant transfers between levels at December 31.

A summary of the assets and liabilities at fair value at December 31, 2013 and 2012, set forth by level within the fair value hierarchy, is as follows (in thousands):

Assets at Fair Value as of December 31, 2013

Active Markets Other Significant for Identical Observable Unobservable Assets Inputs Inputs Totals (Level 1) (Level 2) (Level 3) Assets: Cash equivalents — money market funds $ 181,171 $ 181,171 $ - $ - Restricted investments — deferred compensation: Money market funds 3,202 3,202 Mutual funds:

Domestic stock funds 4,951 4,951 Balanced funds 1,131 1,131 Fixed income funds 1,324 1,324 International stock funds 1,677 1,677 Interest rate contracts 18,653 18,653 Commodity derivatives 3,109 3,106 3 Total assets $ 215,218 $ 196,562 $ 18,656 $ - Liabilities: Interest rate contracts $ 2,227 $ - $ 2,227 $ - Commodity derivatives 5,071 3,499 1,572

Total liabilities $ 7,298 $ 3,499 $ 3,799 $ -

43 Notes to Consolidated Financial Statements CONTINUED

Assets at Fair Value as of December 31, 2012 Active Markets Other Significant for Identical Observable Unobservable Assets Inputs Inputs Totals (Level 1) (Level 2) (Level 3)

Assets: Cash equivalents — money market funds $ 294,773 $ 294,773 $ - $ - Restricted investments — deferred compensation: Money market funds 1,920 1,920 Mutual funds: Domestic stock funds 3,911 3,911

Balanced funds 1,172 1,172 Fixed income funds 2,840 2,840 International stock funds 919 919

Interest rate contracts 12,954 10,712 2,242

Commodity derivatives 2,754 1,315 1,439 Total assets $ 321,243 $ 306,850 $ 12,151 $ 2,242

Liabilities: Interest rate contracts $ 9,560 $ - $ 9,560 $ - Commodity derivatives 1,863 80 1,783 Total liabilities $ 11,423 $ 80 $ 11,343 $ -

The changes in GRE’s Level 3 assets measured at fair MUTUAL FUNDS — Shares of registered investment value on a recurring basis during the year ended companies (mutual funds) are categorized as Level 1; December 31, 2013, are as follows (in thousands): they are valued at quoted market prices that represent the net asset value of shares held at year-end. Interest Rate Contracts INTEREST RATE CONTRACTS — Fair value is Balance — beginning of year $ 2,242 determined by comparing the difference between the net present value of the cash flows for the swaps at their Total gains or losses (realized/unrealized) initial fixed rate and the current market fixed rate. The included in regulatory liabilities 1,078 initial fixed rate is quoted in the swap agreement and Purchases the current market fixed rate is corroborated by

Sales (3,320) observable market data and categorized as Level 2. The

Settlements fair value of the swaption is estimated utilizing an option- pricing model based on several inputs, including the Balance — end of year $ - notional amount, the forward London InterBank Offered Rate (LIBOR) swap rates, the option volatility, the fixed For the years ended December 31, 2013 and 2012, rate on the underlying swap, the time to expiration, the there were no significant transfers in or out of Levels 1, 2, term of the underlying swap, and discount rates. As or 3. valuations of comparable instruments are generally not MONEY MARKET ACCOUNTS — Fair value is able to be corroborated by market data, the swaption is determined using quoted prices in active markets for categorized as Level 3. identical assets.

44 Notes to Consolidated Financial Statements CONTINUED

COMMODITY DERIVATIVES — Exchange traded futures adjusted, as GRE has the ability and intent to perform contracts and financial transmission rights are valued at under each of the contracts. In the instance of asset quoted market prices and are categorized as Level 1. positions, GRE considers general market conditions and

Fair value for forward contracts is determined by the observable financial health and outlook of specific comparing the difference between the net present value counterparties; forward looking data, such as credit of the cash flows at the initial price and the current default swaps, when available; and historical default market price. The initial price is quoted in the contract probabilities from credit rating agencies in evaluating the and the market price is corroborated by observable potential impact of nonperformance risk to derivative market data. These contracts are categorized as Level 2. positions. Given this assessment, when determining the GRE continuously monitors the creditworthiness of the fair value of derivative assets, the impact of considering counterparties to its derivative contracts and assesses the credit risk was immaterial to the fair value of derivative assets presented in the consolidated balance sheets. counterparties’ ability to perform on the transactions set forth in the contracts. Liability positions are generally not

The estimated fair values of GRE’s financial instruments carried at cost, other than capital leases, at December 31,

2013 and 2012, are as follows and are provided for disclosure purposes only (in millions):

2013 2012

Carrying Fair Carrying Fair Cost Value Cost Value Long-term receivables $ 3.6 $ 3.5 $ 4.7 $ 4.7 Long-term obligations 2,646.0 3,066.5 2,685.8 3,292.8

The estimated fair values of GRE’s long-term receivables and long-term obligations, other than capital leases, were based on present value models using current rates available for similar issues with similar credit ratings. These fair value measurements would be characterized as Level 2. The carrying amounts of GRE’s remaining financial instruments included in current assets and current liabilities approximate their fair value. For other investments — capital term certificates, the carrying amount is assumed to approximate fair value, as these instruments generally must be held as a condition of financing.

9. INCOME TAXES

GRE is a nonprofit taxable cooperative subject to federal and state income taxation and is allowed a deduction for margins allocated to members as patronage capital.

GRE had no regular federal income tax expense during 2013, 2012, or 2011 due to a net loss position. This net loss position was primarily the result of the allocation of margins to members, tax depreciation in excess of depreciation recorded for financial reporting purposes, and the deduction of certain costs for income tax reporting purposes, which

were deferred for financial reporting purposes.

45 Notes to Consolidated Financial Statements CONTINUED

The consolidated deferred income taxes as of December 31, 2013 and 2012, are as follows (in thousands): 2013 2012

GRE current deferred income tax assets — net $ 26,636 $ 23,220 Falkirk current deferred income tax assets — net 546 773 Consolidated current deferred income tax asset — net $ 27,182 $ 23,993 Falkirk noncurrent income tax asset — net: Long-term deferred tax assets $ 12,427 $ 18,664 Long-term deferred tax liabilities (9,012) (15,720) Total deferred tax asset $ 3,415 $ 2,944

GRE noncurrent income tax liability — net: Long-term deferred tax liabilities $ 215,063 $ 190,057

Long-term deferred tax assets (188,758) (167,341)

Valuation allowance 331 504

Total deferred income tax liability $ 26,636 $ 23,220

The noncurrent income tax asset — net is recorded in benefit will be sustained, GRE records the largest amount deferred charges — other in the consolidated balance of tax benefit with a greater than 50% likelihood of sheets. being realized upon ultimate settlement with a taxing

These deferred taxes result from differences in the authority that has full knowledge of all relevant information. For those income tax positions where it is not recognition of accounting transactions for tax and financial reporting purposes. The primary temporary more likely than not that a tax benefit will be sustained, no tax benefit has been recognized in the consolidated differences relate to depreciation, the sale and leaseback transaction, deferred charges, retirement financial statements. Where applicable, associated interest and penalties will also be recognized. benefits, and certain financial reserves not deductible for tax purposes until paid. GRE has determined that its taxable years ended

As of December 31, 2013, GRE had a federal net December 31, 2007, 2008, 2011, 2012, and 2013, are operating loss (NOL) of $379.4 million that can be used still subject to examination under federal tax statutes. to offset taxable income in the carryforward period. GRE has completed examinations by the Internal Revenue

These NOLs expire in varying amounts from 2022 Service of taxable years ended December 31, 2009 through 2031. GRE has a tax credit carryforward of and 2010. GRE’s taxable years ended December 31, $7.5 million and a prepaid alternative minimum tax 2007 through 2013, are still subject to examination (AMT) credit of $0.6 million. The tax credits expire in under state tax statutes. varying amounts from 2014 through 2031, while the AMT TANGIBLE PROPERTY REGULATIONS — In September credit has no expiration. 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with amounts There were no uncertain tax positions that were material to GRE’s results of operations or financial position and paid to acquire, produce, or improve tangible property. The regulations have the effect of a change in law, and GRE does not expect any change to these positions in the next 12 months. as a result, the impact should be taken into account in the period of adoption. In general, such regulations apply to In the ordinary course of business, there is inherent tax years beginning on or after January 1, 2014, with uncertainty in quantifying GRE’s income tax positions. early adoption permitted. Procedural guidance is

GRE assesses its income tax positions and records tax expected in early 2014 to facilitate implementation. GRE benefits for all years subject to examination based upon expects to implement most, if not all, of the provisions of management’s evaluation of the facts, circumstances, and the final regulations in 2014 and analysis performed to information available at the reporting dates. For those date indicates there would be no material impact to the tax positions where it is more likely than not that a tax consolidated financial statements.

46 Notes to Consolidated Financial Statements CONTINUED

10. PENDING LITIGATION, CONTINGENCIES, AND COMMITMENTS MIDCONTINENT INDEPENDENT SYSTEM OPERATOR (MISO) — The MISO market began on April 1, 2005. Due to the nature of this market, various disputes and resettlements have taken place and some are still in process. It is the opinion of management that the resolution of the various open MISO disputes and resettlements will not have a material effect on the financial position, results of operations, or cash flows. LITIGATION — GRE is involved in various legal actions arising in the normal course of business. It is the opinion of management that the resolution of such actions will not have a material adverse effect on the financial position, results of operations, or cash flows. FUTURE COMMITMENTS — GRE is committed to the following estimated expenditures under the various purchased power and fuel contracts discussed below (in millions):

2014 2015 2016 2017 2018 Thereafter Total

Dairyland Power Cooperative $ 19.1 $ 20.0 $ 21.2 $ 20.5 $ 21.1 $ 238.4 $ 340.3

Wind energy purchases 62.9 64.5 66.9 66.9 67.5 1,182.5 1,511.2

Other purchased power 15.0 9 .6 5 .0 5 .0 5 .0 40.1 79.7 Fuel contracts 8.2 8.2 $ 105.2 $ 94.1 $ 93.1 $ 92.4 $ 93.6 $ 1,461.0 $ 1,939.4

PURCHASED POWER CONTRACTS — GRE has a power $59.9 million, and $55.3 million for 2013, 2012, and agreement with Dairyland Power Cooperative (DPC) to 2011, respectively.

share costs and benefits of a 379-megawatt generating GRE has long-term power agreements for the purchase unit (“Genoa 3”) located near Genoa, Wisconsin. This of energy from other various power suppliers. Agreement agreement remains in effect until the retirement of the terms vary with the longest extending to 2045. GRE is unit from service or until the payment in full of all obligated to purchase energy at either fixed or variable obligations arising from the construction and operation of prices for the term of the agreements. GRE also has a the unit, whichever is later. Under the agreement, the contract for transmission associated with some of these capacity costs are shared equally by GRE and DPC, and agreements that extends into 2015. GRE’s expenses for

GRE is required to pay additional amounts for actual energy and transmission purchased under these

energy purchased. Included as future commitments in the agreements were $18.3 million, $19.4 million, and $18.0

table above is GRE’s share of the estimated annual million for 2013, 2012, and 2011, respectively. capacity costs through the end of Genoa 3’s economic useful life, which is estimated by DPC to be 2029. GRE’s FUEL CONTRACTS — GRE has an agreement with Cloud expenses for capacity, energy, and transmission charges Peak Energy to provide coal to Stanton in North Dakota. under the agreement were $41.3 million, $38.3 million, GRE also has an agreement with The Burlington Northern and $33.6 million for 2013, 2012, and 2011, Santa Fe Railroad for the delivery of this coal. The coal respectively. At December 31, 2013 and 2012, GRE had agreement runs through the end of 2018; however, there provided $12.0 million and $8.8 million, respectively, to are no minimum commitments with this contract. The freight agreements extend through the end of 2014. DPC to fund its share of fuel inventory, which is allowed under the agreement. This amount is recorded in GRE’s expenses under these agreements were $18.1 million, $22.7 million, and $22.6 million in 2013, 2012, prepaids and other current assets in the consolidated balance sheets. and 2011, respectively.

GRE has long-term power agreements for the purchase RECLAMATION GUARANTEE — Falkirk is required by

of 468 megawatts of wind energy from various power the North Dakota Public Service Commission (PSC) to carry

suppliers. The agreements have varying terms and some bonds to cover reclamation of mined lands in the event the

have extension options. The longest contract term extends surface mining and reclamation permit is revoked. These

to 2041. GRE is obligated to purchase the energy bonds are released by the PSC after a period of time,

generated from these facilities at fixed prices for the generally at least 10 years after final reclamation is

term of the agreements. GRE’s expenses for energy complete and it has been determined that the land has purchased under these agreements were $60.5 million, been returned to its approved postmining use. Under the

47 Notes to Consolidated Financial Statements CONTINUED

PSC’s self bond program, GRE provides a guarantee for MEMBER GUARANTEES — As of December 31, 2013 the majority of Falkirk’s reclamation obligation. As of and 2012, GRE has guaranteed $0.8 million and $1.1 December 31, 2013, the aggregated value of this million, respectively, of rural development loans that guarantee is $68.5 million. No liability has been recorded various member distribution cooperatives have secured in the consolidated financial statements related to this from Rural Utilities Services. The guaranteed loans are guarantee as of December 31, 2013 and 2012. Falkirk collateralized in the form of land, buildings, or has recorded an asset retirement obligation for the costs to equipment. A liability of $0.1 million and $0.2 million has cover final reclamation (see Note 14). been recorded in the consolidated financial statements LETTER OF CREDIT — GRE has issued a letter of credit related to these guarantees as of December 31, 2013 for $1.7 million to MISO in connection with its commodity and 2012, respectively. derivatives. No amount is outstanding as of December 31, 2013.

11. DEFERRED CHARGES AND REGULATORY LIABILITIES

The amounts of deferred charges recorded by GRE and Falkirk as of December 31, 2013 and 2012, are as follows (in thousands):

2013 2012 Regulatory assets: Premiums on refinanced long-term debt $ 11,186 $ 12,329 Postretirement benefit plans 29,642 55,737

Interest rate derivatives 2,226 9,561 Settled interest rate hedging instruments 62,706 66,430 Transaction costs related to NDRC 9,186 9,890 Refined coal purchase costs 30,000 18,000 Interest and plant costs 17,336 17,336 Scheduled major outage maintenance 27,075

Other 476 530 Total regulatory assets 189,833 189,813 Other deferred charges 26,058 35,336

Total deferred charges $ 215,891 $ 225,149 Reported as:

Deferred charges — financing related $ 97,259 $ 117,756

Deferred charges — other 118,632 107,393 Total deferred charges $ 215,891 $ 225,149

The amounts of regulatory liabilities recorded by GRE as of December 31, 2013 and 2012, are as follows (in thousands):

2013 2012

Regulatory liabilities: Interest rate derivatives $ 18,653 $ 12,954 Settled interest rate hedging instruments 36,212

Deferred revenue 13,750

Incentive-based rate treatment 10,422 4,237 Other 4,858 3,395

Total regulatory liabilities $ 83,895 $ 20,586

48 Notes to Consolidated Financial Statements CONTINUED

PREMIUMS ON REFINANCED LONG-TERM DEBT REFINED COAL PURCHASE COSTS — In connection with GRE has refinanced various issues of long-term debt, the facility lease with NDRC and the related refined coal which resulted in the payment of premiums. This amount purchase agreement, GRE is deferring certain refined will be fully amortized by 2038, the maturity date of the coal purchase costs until January 31, 2020, which is the 2007A bonds. exercise date of the purchase option to buy out of the POSTRETIREMENT BENEFIT PLANS — GRE and Falkirk transaction. GRE plans to expense these costs at the time have defined benefit pension plans and postretirement the purchase option is exercised or amortize over the last medical plans for certain employees. GRE and Falkirk seven years of the lease agreement in the event the record regulatory assets related to items that are purchase option is not exercised. normally reported as accumulated other comprehensive INTEREST AND PLANT COSTS — During 2007, GRE income for these plans. GRE has recorded a regulatory began construction of a generation facility in Spiritwood, asset of $23.6 million and $29.5 million, and Falkirk has North Dakota. GRE delayed construction of this facility recorded a regulatory asset of $6.0 million and $26.2 for portions of 2010 and 2011. GRE has deferred costs million at December 31, 2013 and 2012, respectively. totaling $17.3 million for interest, maintenance, and other These amounts are adjusted each year as a result of the costs associated with this project while construction remeasurement of the obligations related to these plans. activities were suspended. This amount will be amortized

INTEREST RATE DERIVATIVES — GRE has interest rate over the useful life of the facility once it is completed and swaps that have not been settled as of December 31, placed into service, which will be in November 2014. 2013 and interest rate swaps and a swaption that have SCHEDULED MAJOR OUTAGE MAINTENANCE not been settled as of December 31, 2012. Certain During 2013, GRE began deferring scheduled major interest rate swaps have been recorded at fair value as outage maintenance costs for CCS and Stanton and a liability, with an offsetting regulatory asset, of $2.2 amortizing these costs over the maintenance cycle period, million and $9.6 million as December 31, 2013 and which is three years for CCS and four years for Stanton 2012, respectively. Certain interest rate swaps and including the year of the outage. The amortization is swaption are recorded at fair value as an asset, with an included in operation and maintenance expense in the offsetting regulatory liability, of $18.7 million and $13.0 consolidated statement of operations. million as of December 31, 2013 and 2012, respectively. OTHER DEFERRED CHARGES — Other deferred Once these interest rate derivatives are settled, any charges primarily relate to unamortized debt issuance deferred regulatory asset or liability will be amortized costs, deferred lease costs, and deferred income taxes. over the life of the related debt, unless there is no related debt issuance and then the amortization period DEFERRED REVENUE — GRE deferred the recognition will be determined by regulatory accounting. of $13.8 million of member electric revenue during 2013 in accordance with regulatory accounting requirements. SETTLED INTEREST RATE HEDGING INSTRUMENTS This deferred revenue will be recognized in member GRE purchased interest rate swaps related to the 2010D electric revenue in the future as determined by the board bonds and the 2008A bonds (see Note 5). The settlement of of directors. the swaps resulted in payments to the swap counterparties in the amounts of $68.4 million in 2010 and $4.8 million in INCENTIVE-BASED RATE TREATMENT — GRE received 2008. These settled swaps are amortized over the life of approval from the Federal Energy Regulatory the related debt and the amortization is included in interest Commission (FERC) for incentive-based rate treatment for expense in the consolidated statement of operations. During the CapX2020 transmission projects and is collecting a 2013, GRE terminated certain interest rate swaps and a return on investment from MISO while these projects are swaption without a related debt issuance for net proceeds under construction. As a result, GRE has recorded of $36.2 million. The net proceeds from this termination are amortization expense in an amount equal to the interest recorded as a regulatory liability and will be used to capitalized to the project in the current year and has reduce future member rates. recorded an offsetting regulatory liability. Once a project is complete and placed in service, the regulatory TRANSACTION COSTS RELATED TO NDRC liability will be amortized over the useful life of the

GRE incurred $11.3 million in external transaction costs in underlying assets and recorded as a reduction to connection with executing agreements with NDRC, or its depreciation expense. subsidiaries, for the sale and purchase of lignite and coal and for the lease of GRE’s refined coal processing The regulatory assets and regulatory liabilities are facility (see Note 1). This amount is being amortized over recorded as per regulatory accounting requirements and the life of the facility lease, which is through 2027. The have all been approved by the board of directors. amortization is included as fuel expense in the consolidated statement of operations. 49 Notes to Consolidated Financial Statements CONTINUED

12. EMPLOYEE BENEFIT PLANS GRE offers various benefit plans to its employees. Approximately 28% of total employees that receive benefits are represented by two local labor unions under three collective bargaining agreements. Two agreements extend through the end of 2015 and one agreement extends through 2016. PENSION PLANS — GRE has a defined benefit plan that covers certain employees who chose to remain in a defined benefit plan, a nonqualified supplemental defined benefit plan that is frozen, and a qualified defined contribution retirement plan for the other employees. GRE also has a nonqualified defined contribution plan for certain employees. Falkirk has a defined benefit plan that covers employees hired before January 1, 2000, a nonqualified supplemental defined benefit plan that is frozen, and a defined contribution plan for the other employees. During 2013, Falkirk amended the defined benefit plan to freeze pension benefits effective January 1, 2014. As a result of this amendment, Falkirk remeasured the plan and recorded a curtailment loss of $0.4 million during 2013. Changes in benefit obligations and plan assets for all defined benefit plans for the years ended December 31, 2013 and 2012, and the amounts recognized in the consolidated balance sheets as of December 31, 2013 and 2012, are as follows (in thousands): 2013 2012 Falkirk GRE Falkirk GRE Change in benefit obligation: Benefit obligation — beginning of year $ 71,896 $ 65,442 $ 63,924 $ 61,252 Service cost 912 165 1,045 149 Interest cost 2,793 1,887 2,902 2,269

Actuarial (gain) loss (7,772) (3,846) 6,209 5,966

Curtailment (5,360) Plan amendment (151) Benefits paid (2,404) (4,980) (2,184) (4,194) Benefit obligation — end of year 59,914 58,668 71,896 65,442

Change in plan assets: Fair value of plan assets — beginning of year 47,698 50,571 39,812 47,146 Actual return on assets 9,004 2,247 5,070 3,655 Employer contributions 4,902 5,618 5,000 3,964 Benefits paid (2,404) (4,980) (2,184) (4,194) Fair value of plan assets — end of year 59,200 53,456 47,698 50,571 Funded status — end of year $ (714) $ (5,212) $ (24,198) $ (14,871)

Amounts recognized as components of net periodic benefit cost as of December 31, 2013 and 2012, are as follows (in thousands): 2013 2012 Falkirk GRE Falkirk GRE

Other noncurrent liabilities $ 714 $ 5,212 $ 24,198 $ 14,871

Amounts not yet recognized as components of net periodic benefit cost as of December 31, 2013 and 2012, are as follows (in thousands): 2013 2012 Falkirk GRE Falkirk GRE Transition obligation $ - $ 268 $ - $ 330 Prior-service cost 163 89 890 117 Accumulated loss 4,327 21,835 24,125 27,381

$ 4,490 $ 22,192 $ 25,015 $ 27,828

50 Notes to Consolidated Financial Statements CONTINUED

The accumulated benefit obligation for the GRE defined benefit pension plans were $57.6 million and $64.4 million as of December 31, 2013 and 2012, respectively. The accumulated benefit obligation for the Falkirk defined benefit pension plan was $59.9 million and $64.7 million as of December 31, 2013 and 2012, respectively. Components of net periodic benefit cost for the GRE and Falkirk defined benefit pension plans as of December 31, 2013, 2012, and 2011, are as follows (in thousands):

2013 2012 2011 Falkirk GRE Falkirk GRE Falkirk GRE

Service cost $ 912 $ 165 $ 1,045 $ 149 $ 1,143 $ 131 Interest cost 2,793 1,887 2,902 2,269 3,129 2,845 Expected return on assets (3,833) (1,880) (3,397) (1,912) (3,295) (3,640) Amortization of prior-service cost 1,493 28 1,700 35 1,216 30 Recognized net actuarial loss 134 1,333 225 1,145 225 714 Curtailment 442 Amortization of net transition obligation 63 63 63 Net periodic benefit cost $ 1,941 $ 1,596 $ 2,475 $ 1,749 $ 2,418 $ 143

The estimated amounts to be amortized from deferred charges into net periodic benefit cost in 2014 are $1.2 million for the GRE plans and $0.1 million for the Falkirk plans.

Weighted-average assumptions used to determine benefit obligations for GRE and Falkirk defined benefit pension

plans as of December 31, 2013, 2012, and 2011, are as follows:

2013 2012 2011

Falkirk GRE Falkirk GRE Falkirk GRE

Discount rate 4.75% 4.25% 3.90% 3.25% 4.55% 4.20% Rate of compensation increase N/A 3.75 3.75 3.75 3.75 3.75

Weighted-average assumptions used to determine periodic benefit cost for GRE and Falkirk defined benefit pension plans as of December 31, 2013, 2012, and 2011, are as follows:

2013 2012 2011 Falkirk GRE Falkirk GRE Falkirk GRE Discount rate 3.90/4.70% 3.25% 4.55% 4.20% 5.30% 5.10% Rate of compensation increase 3.75 3.75 3.75 3.75 3.75 3.75 Expected return on assets 7.75 4.00 8.25 4.50 8.50 7.75

Falkirk used a discount rate of 3.90% for the period from January 1, 2013, to July 31, 2013, and a rate of 4.70% for the period from August 1, 2013, to December 31, 2013.

During 2012, GRE adjusted its strategy to achieve a mix of approximately 80% for near-term and longer-term benefit payments and 20% of investments for long-term growth. During a portion of 2012, GRE’s strategy was a mix of approximately 60% near-term and longer-term benefit payments and 40% of investments for long-term growth. The target allocations for the plan assets for 2013 and 2012 are 80% fixed-income securities and 20% equity securities. The investment strategy has a wide diversification of asset types, fund strategies, and fund managers. Equity securities primarily include investments in large-cap and mid-cap companies located in the United States; however, during a portion of 2012, the plan also invested in small-cap companies primarily located in the United States. In addition, during a portion of 2012, the plan invested in international equities, which were predominately, but not exclusively, located in developed countries and large-cap in focus.

51 Notes to Consolidated Financial Statements CONTINUED

GRE’s defined benefit plan investments at December 31, 2013 and 2012, are as follows (in thousands):

2013 2012 Cash $ 317 $ 312 Money market funds 6,052 786 Mutual funds: Domestic stock funds 11,996 10,055 Fixed income funds 35,091 39,418 $ 53,456 $ 50,571

A summary of GRE’s defined benefit plan’s investments measured at fair value at December 31, 2013 and 2012, set forth by level within the fair value hierarchy, is as follows (in thousands):

Assets at Fair Value as of December 31, 2013 Active Markets Other Significant for Identical Observable Unobservable Assets Inputs Inputs Totals (Level 1) (Level 2) (Level 3) Money market funds $ 6,052 $ 6,052 $ - $ -

Mutual funds: Domestic stock funds 11,996 11,996 Fixed income funds 35,091 35,091 $ 53,139 $ 53,139 $ - $ -

Assets at Fair Value as of December 31, 2012 Active Markets Other Significant for Identical Observable Unobservable Assets Inputs Inputs Totals (Level 1) (Level 2) (Level 3) Money market funds $ 786 $ 786 $ - $ - Mutual funds: Domestic stock funds 10,055 10,055 Fixed income funds 39,418 39,418

$ 50,259 $ 50,259 $ - $ -

For the years ended December 31, 2013 and 2012, there were no significant transfers in or out of Levels 1, 2, or 3.

MONEY MARKET ACCOUNTS — Fair value is determined using quoted prices in active markets for identical assets.

MUTUAL FUNDS — Shares of registered investment companies (mutual funds) are categorized as Level 1; they are valued at quoted market prices that represent the net asset value of shares held at year-end. The Falkirk plan maintains an investment policy that, among other things, establishes a portfolio asset allocation methodology with percentage allocation bands for individual asset classes. This investment policy sets target allocations for the plan assets ranging from approximately 50% to 78% in equity securities and 30% to 50% in fixed-income securities. The investment policy further divides investments in equity securities among U.S. and non-U.S. companies. The investment policy provides that investments be reallocated between classes as balances exceed or fall below the appropriate allocation bands.

52 Notes to Consolidated Financial Statements CONTINUED

Falkirk’s defined benefit plan investments at December 31, 2013 and 2012, are as follows (in thousands):

2013 2012 Money market funds $ 321 $ 488 Domestic equity securities 31,707 24,804 International equity securities 7,670 5,944 Fixed income securities 19,502 16,462 $ 59,200 $ 47,698

The invested funds are stated at fair value using quoted market prices in active markets for identical assets as the fair value measurement (Level 1). For the years ended December 31, 2013 and 2012, there were no significant transfers in or out of Levels 1, 2, or 3. To develop the expected long-term rate of return on asset assumptions, GRE and Falkirk considered the historical returns and the future expectations for returns on each asset class as well as target allocation of the pension portfolio. This resulted in 2013 and 2012 long-term rate of return assumptions of 4.0% and 4.5%, respectively, for GRE and

2013 and 2012 long-term rate of return assumptions of 7.75% and 8.25%, respectively, for Falkirk. The expected future benefits to be paid as of December 31, 2013, are as follows (in thousands):

Years Ending December 31 Falkirk GRE

2014 $ 2,601 $ 5,307

2015 2,899 4,933 2016 3,162 4,805 2017 3,415 5,193 2018 3,696 4,394 2019–2022 20,783 19,610

GRE and Falkirk expect to make contributions of approximately $0.4 million and $0 million, respectively, to the defined benefit pension plans during 2014. GRE makes defined contributions to all employees not covered in the GRE defined benefit plan and matching contributions to all eligible employees under a defined contribution savings plan. Effective January 1, 2013, GRE merged its defined contribution plan with its defined contribution savings plan and renamed it a retirement plan. GRE made savings and matching contributions to its defined contribution retirement plan of $8.7 million in 2013 and to its two plans of $8.0 million and $7.7 million in 2012 and 2011, respectively. Falkirk’s contributions to the defined contribution pension plan were $1.3 million, $1.2 million, and $0.9 million for 2013, 2012, and 2011, respectively. Falkirk’s contributions to a defined contribution savings plan were $1.7 million, $1.6 million, and $1.4 million for 2013, 2012, and 2011, respectively.

POSTRETIREMENT MEDICAL BENEFITS — Employees retiring from GRE who elected to remain in the defined benefit pension plan, have attained age 55, and have at least 10 years of service are entitled to participate in the GRE medical insurance plan. Benefits to the former employees are in the form of monthly payments to cover a portion of the premium charged for participation in the program. Additionally, employees retiring under a previously offered early retirement program could elect to participate in a medical insurance plan until they reach age 65. Benefits to these retirees are in the form of monthly payments to cover a portion of the premium charged for participation in the program. Employees retiring from Falkirk also are eligible to participate in Falkirk’s medical insurance plan with the benefit in the form of a supplement to the premium. Costs for the unfunded postretirement medical plan are recognized in the year the employees render service.

53 Notes to Consolidated Financial Statements CONTINUED

Changes in benefit obligations for the years ended December 31, 2013 and 2012, and amounts recognized in the consolidated balance sheets as of December 31, 2013 and 2012, are as follows (in thousands):

2013 2012 Falkirk GRE Falkirk GRE

Change in benefit obligation: Benefit obligation — beginning of year $ 7,670 $ 4,132 $ 7,497 $ 4,853 Service cost 139 6 160 9 Interest cost 230 119 289 175 Actuarial (gain) loss (81) (252) 255 105

Benefits paid (477) (777) (531) (1,010)

Benefit obligations — end of year $ 7,481 $ 3,228 $ 7,670 $ 4,132

Amounts recognized in balance sheets as of December 31, 2013 and 2012, are as follows (in thousands):

2013 2012 Falkirk GRE Falkirk GRE Current liabilities $ 586 $ 639 $ 550 $ 817

Other noncurrent liabilities 6,895 2,589 7,120 3,315 $ 7,481 $ 3,228 $ 7,670 $ 4,132

Amounts not yet recognized as components of net periodic benefit cost as of December 31, 2013 and 2012, are as follows (in thousands):

2013 2012 Falkirk GRE Falkirk GRE

Prior service (credit) cost $ (134) $ 238 $ (694) $ 206 Accumulated loss 1,347 1,195 1,551 1,518

$ 1,213 $ 1,433 $ 857 $ 1,724

Components of net periodic postretirement benefits cost for December 31, 2013, 2012, and 2011, are as follows (in thousands):

2013 2012 2011

Falkirk GRE Falkirk GRE Falkirk GRE

Service cost $ 139 $ 6 $ 160 $ 9 $ 193 $ 5

Interest cost 230 119 289 175 365 239

Amortization of prior service credit (560) (31) (560) (31) (560) (49)

Recognized net actuarial losses 123 71 94 50 178 53 Net periodic (benefit) cost $ (68) $ 165 $ (17) $ 203 $ 176 $ 248

The estimated amounts to be amortized from deferred charges into net periodic benefit cost in 2014 are a net credit of less than $0.1 million for the GRE plan and a net credit of less than $0.1 million for the Falkirk plan.

The weighted-average assumptions used to determine postretirement obligations and net periodic postretirement benefit costs for the years 2013, 2012, and 2011 are the same applicable assumptions used for the defined benefit pension plans except for Falkirk’s discount rate. Falkirk used 3.85%, 3.05%, and 3.90% for the discount rate for 2013, 2012, and 2011, respectively.

54 Notes to Consolidated Financial Statements CONCLUDED

The expected future benefit payments to be paid as of the offsetting capitalized asset retirement cost to expense December 31, 2013, are as follows (in thousands): using the straight-line method over the remaining useful life of the related long-lived asset being retired. Years Ending December 31 Falkirk GRE GRE has recorded obligations related to capping and reclamation of ash disposal sites for certain base load power 2014 $ 587 $ 640 plants, obligations related to future removal and disposal of 2015 682 495 asbestos, and obligations related to the disposal of equipment 2016 793 369 containing polychlorinated biphenyls. During 2012, GRE 2017 848 268 evaluated its obligation for CCS’s ash disposal sites and due to 2018 859 230 changes in the estimated reclamation costs and timing for this obligation, GRE recorded an additional liability of $7.4 million. 2019–2022 3,973 910 During 2013, GRE evaluated the timing of the CCS and Stanton The effect of a one percentage point change in health care ash disposal obligations in conjunction with GRE’s change in cost trend rates on service and interest costs is not material in estimated service lives for CCS and Stanton and recorded an relation to the consolidated financial statements taken as a additional liability of $7.9 million due to this change in whole. estimate. Falkirk has recorded an obligation related to the final costs to close its surface mines and reclaim the land disturbed as 13. MEMBER RELATED-PARTY TRANSACTIONS a result of normal mining operations. There are no assets legally restricted for purpose of settling these obligations. GRE provides electric and other services to the members. GRE received revenue of $836.4 million, $803.3 million, and GRE also has an obligation to retire its direct current transmission $769.4 million in 2013, 2012, and 2011, respectively, for line upon abandonment. This line transmits the energy from CCS these services. GRE received 39.8%, 40.4%, and 39.7% of in North Dakota to the GRE service territory in Minnesota. GRE total member revenue from two members for the years has not recorded a liability related to this obligation because ended December 31, 2013, 2012, and 2011, respectively. the fair value cannot be reasonably estimated due to the retirement date being indefinite at this time. GRE also receives various services from the members and paid $9.9 million, $7.5 million, and $10.4 million for these A reconciliation of the beginning and ending aggregate services in 2013, 2012, and 2011, respectively. carrying amount of the obligations as of December 31, 2013 and 2012, is as follows (in thousands): GRE has accounts receivable from the members of $146.0 million and $126.5 million at December 31, 2013 and 2012, 2013 2012 respectively. GRE has notes receivable from the members of Balance — beginning of year $ 40,347 $ 31,259 $0.6 million and $2.2 million as of December 31, 2013 and New obligations incurred 101 2012, respectively. These notes were issued at face value and have an effective average interest rate of 5%. Obligations recorded as a result of changes in estimated cash flows 7,911 7,666 GRE has notes payable to the members of $25.0 million and Accretion expense 2,606 1,856 $20.6 million at December 31, 2013 and 2012, respectively. Obligations settled (609) (535) These notes relate to funds invested with GRE by the members Balance — end of year $ 50,255 $ 40,347 under a member investment program. These funds are used by GRE to reduce short-term borrowings. The members receive

investment earnings based on GRE’s blended rate of return for These obligations are recorded in other noncurrent liabilities specified investments, adjusted for administrative costs. in the consolidated balance sheets. The obligations settled are the only transactions recognized in the consolidated 14. ASSET RETIREMENT OBLIGATIONS statements of cash flows. Generally accepted accounting principles require the 15. SUBSEQUENT EVENTS recording of liabilities related to asset retirement On January 16, 2014, GRE amended and extended for one obligations. An asset retirement obligation is the result of legal or contractual obligations associated with the year its $600.0 million unsecured revolving credit facility. The facility now expires on June 6, 2017. retirement of a tangible long-lived asset that result from the acquisition, construction, or development and/or the During January and February 2014, DSAF obtained additional normal operation of a long-lived asset. GRE determines long-term debt financing of $50.0 million for the construction of these obligations based on an estimated asset retirement the DSA biorefinery plant. Effective March 1, 2014, in exchange cost adjusted for inflation and projected to the estimated for a 20.97% ownership interest, MAG transferred 16,400 settlement dates, and discounted using a credit-adjusted, ownership units to third-party investors for $16.4 million. risk-free interest rate. GRE allocates the amortization for 55 M ANAGEMENT AND BOARD OF DIRECTORS

GREAT RIVER ENERGY SENIOR STAFF David Hernke, Goodhue County Itasca-Mantrap Cooperative Electrical Cooperative Electric Association, David Saggau, president and CEO Park Rapids Tim Kivi, Itasca-Mantrap Cooperative Michael Monsrud, president and CEO Jon Brekke, vice president, membership and Electrical Association energy markets Kandiyohi Power Cooperative, Spicer Dale Anderson, Kandiyohi Power David George, CEO Jim Jones, vice president and chief Cooperative information officer Lake Country Power, Grand Rapids Robert Bruckbauer, Lake Country Power Will Kaul, vice president, transmission Greg Randa, general manager Ken Hendrickx, Lake Region Electric Rick Lancaster, vice president, generation Lake Region Electric Cooperative, Cooperative Pelican Rapids Eric Olsen, vice president and general Oria Brinkmeier, McLeod Cooperative Tim Thompson, CEO counsel Power Association McLeod Cooperative Power Kandace Olsen, vice president, Harold Harms, Mille Lacs Energy Association, Glencoe communications and human resources Cooperative Gary Connett, acting general manager Greg Ridderbusch, vice president, business Lee York, Nobles Cooperative Electric Meeker Cooperative Light & Power development and strategy Association, Litchfield Bruce Leino, North Itasca Electric Tim Mergen, CEO/general manager Larry Schmid, vice president and chief Cooperative, Inc. financial officer Mille Lacs Energy Cooperative, Aitkin William O’Brien, Runestone Electric Ralph Mykkanen, general manager Louy Theeuwen, director, executive services Association Minnesota Valley Electric Dennis O’Donnell, Stearns Electric Cooperative, Jordan GREAT RIVER ENERGY BOARD OF Association Roger Geckler, general manager DIRECTORS Nobles Cooperative Electric, Chair Michael Thorson, Todd-Wadena MEMBER COOPERATIVE CEOs Worthington Electric Cooperative Richard Burud, general manager Agralite Electric Cooperative, Benson Vice Chair Sherman Liimatainen, Lake Kory Johnson, general manager North Itasca Electric Cooperative, Inc., Country Power Bigfork Arrowhead Cooperative, Inc., Lutsen Jared Echternach, CEO Secretary Gary Wilson, Steele-Waseca Joe Buttweiler, acting general manager Cooperative Electric Redwood Electric Cooperative, BENCO Electric Cooperative, Mankato Clements East Treasurer Robert Thompson, Wade Hensel, general manager Ron Horman, general manager Central Energy Brown County Rural Electrical Runestone Electric Association, Arrowhead Cooperative, Thomas Spence, Association, Sleepy Eye Alexandria Inc. Wade Hensel, general manager Rick Banke, CEO Brad Leiding, BENCO Electric Cooperative Connexus Energy, Ramsey South Central Electric Association, Mike Rajala, president and CEO Reuben Kokesch, Brown County Rural St. James Electrical Association Cooperative Light and Power, Ron Horman, general manager Two Harbors Donald Holl, Connexus Energy Stearns Electric Association, Melrose Steven Wattnem, general manager Rick Banke, general manager James Leroux, Connexus Energy Crow Wing Power, Brainerd Steele-Waseca Cooperative Electric, Peggy Kuettel, Cooperative Light and Bruce Kraemer, CEO Owatonna Power Dakota Electric Association, Farmington Syd Briggs, general manager Robert Kangas, Crow Wing Power Greg Miller, president and CEO Todd-Wadena Electric Cooperative, Wadena Dwight Thiesse, Crow Wing Power East Central Energy, Braham Steve Shurts, president and CEO Robin Doege, president and CEO Margaret Schreiner, Dakota Electric Wright-Hennepin Cooperative Electric Association Federated Rural Electric Association, Jackson Association, Rockford Clay Van De Bogart, Dakota Electric Richard Burud, general manager Mark Vogt, president and CEO Association Goodhue County Cooperative Electric, Joe Morley, East Central Energy Zumbrota Management and board of directors listed as of Douglas Fingerson, general manager printing of annual report.

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