Emera Maine Municipalization Review

November 10, 2019

www.ceadvisors.com

TABLE OF CONTENTS

Executive Summary ...... 3 Overview ...... 4 Historical Formation of Municipal and Cooperative Electric Utilities ...... 4 Recent Municipalization Experience ...... 4 Acquisition of the Utility ...... 7 Case Studies on Municipalization...... 10 City of Boulder ...... 10 Winter Park, Florida ...... 13 Public Utility District No. 1 of Jefferson County ...... 13 Privatizations ...... 15 Completed Privatizations ...... 15 Potential Privatization ...... 19 Public Power Authorities ...... 21 Bonneville Power Administration ...... 22 Tennessee Valley Authority ...... 23 Public Power vs. Investor-Owned Utility Rate Comparison...... 25

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EXECUTIVE SUMMARY

Concentric Energy Advisors is an energy consulting firm comprised of utility regulation, economic and energy market experts. Nearly two decades of experience in the area of utility municipalization strongly leads us to conclude that forming a public power authority in Maine would be challenging, even if a compelling economic and public benefits case existed to do so. Our expert analysis concludes: Existing Public Power Authorities Are NOT Relevant Comparisons To Forming A New Public Power Authority  Most large regional public power authorities where established in the 1920’s and 1930s, when generation and transmission/distribution companies were initially created to electrify rural America.  These systems were built slowly and could expand as the need for electric power increased.  Today communities are already built out, with large distribution systems in place. To create a new public power authority – at today’s market prices – would require large amounts of capital to be raised. Nearly all of the 900 Cooperatives and 2,200 Municipal Systems Were Formed In The Early 1900’s And Rarely Through An Acquisition Approach.  Only 10 of 63 electric utility municipalization efforts in the U.S. since 2000 have been completed, one of which was later sold back to the utility due to mismanagement and cost escalation.  These recent efforts have largely failed for a variety of reasons, including abandonment by the municipal government after consideration of a feasibility study or rejection by the voters after the government officials bring the decision to a vote. The Latest Municipal Trend Has Been TOWARD Privatization.  Instead of trends toward municipalization since 2000, the trend has been more toward privatization, or the sale of municipal assets to investor-owned utilities.  Since 2010, there have been six successful electric utility municipal privatization efforts in six states, as well as several natural gas utility privatizations. In addition, in 2019, one of the largest municipal electric utilities in the country recently announced it is considering privatization. Given the challenges to forming a public power authority, the lack of compelling evidence to demonstrate that an effort would be successful and the move toward municipal privatization rather than municipalization, it is not advisable for Maine to pursue this path. If it were to pursue this path, not only would the outcome be uncertain but the path to get there would be uncertain given questions around the legality of the necessary acquisition and just compensation. It is certain that the process would take many years and considerable expense to navigate.

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OVERVIEW

Forming a public power authority in Maine would be challenging, even if a compelling economic and public benefits case existed to do so. Most large regional public power authorities were established decades ago, and there has been no state-wide public power authority established in the United States, meaning there is limited experience by which to compare Maine’s current proposal. However, there is experience within the last 20 years regarding the municipalization of local utility electric distribution systems, and the process and implications regarding these community-driven municipalization efforts are similar and informative to what Maine may experience if it pursued development of a state-wide public power authority. Establishing a public power authority, like municipalization, is making a likely irrevocable decision to finance and acquire assets from the existing utility provider(s), assuming the obligations of providing reliable, safe, and affordable electric service, and forming an organization and governance structure to manage and operate the utility. Such efforts not only commit to acquiring existing electric assets, but to maintain the electric facilities according to national standards and to continue making sufficient investments to support the services that all customers expect.

HISTORICAL FORMATION OF MUNICIPAL AND COOPERATIVE ELECTRIC UTILITIES The majority of the municipal and cooperative electric utilities in the United States were established as early as 1900, and most municipal utilities were formed during the 1920s and 1930s. In the past, communities were much smaller, and electric distribution systems could expand slowly as the need for electric power increased. Capital costs were incurred over time, and municipal electric systems grew gradually, keeping pace with expanding populations. However, as noted by the Edison Electric Institute, the conditions under which public power was established nearly 100 years ago no longer exist today.1 Today most communities already are built out with large electric distribution systems in place, meaning those communities that seek to municipalize local utility ownership and operation have to purchase or build entire systems at today’s market prices. This creates the need for large amounts of capital to be raised and spent all at once, and that a new municipal utility would have to compete with other local government priorities for capital investment.2

RECENT MUNICIPALIZATION EXPERIENCE The impetus for considering municipalization varies but often centers around issues such as:

1 Edison Electric Institute, “Municipalization in a New Energy Environment - It Doesn’t Work”, November 2005, at 9. 2 Id., at 3.

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(1) desire for local control of the provision of electricity; (2) the prospect of obtaining a greener electricity supply; (3) dissatisfaction with the existing utility supplier attributable to price and/or perceived service issues; and/or (4) perception that electricity prices will be lower with municipal ownership due to financing advantages or the belief that it will be possible to bypass costs incurred by the existing utility to provide service. The process for municipalization of an electric utility can take many years. If a petition to municipalize is challenged, regulatory proceedings typically commence through a public utility commission (“PUC”) proceeding. The PUC determines whether or not the municipal operation of the electric utility system is in the public interest. Significant costs can be incurred during this process to retain extensive legal and consulting services. The decisions made by the PUC are reviewable by courts of appeal, which can further extend the legal process. Even after the legality of the acquisition and just compensation are determined, the process for municipalization of an electric utility and all of the requirements for starting and operating a new utility must also be undertaken.

NEARLY ALL OF THE MORE THAN 900 COOPERATIVES AND 2,200 MUNICIPAL ELECTRIC SYSTEMS WERE FORMED IN THE EARLY 1900S, AND RARELY THROUGH AN ACQUISITION APPROACH. AS SHOWN IN

Figure 1, only 10 of 63 municipalization efforts in the U.S. since 2000 have been completed, one of which was later sold back to the utility due to mismanagement and cost escalation experienced by the municipal utility. One community has received city approval to go forward with municipalization, and seven additional communities are currently considering or seeking the necessary approvals for municipalization. The remaining communities have decided not to proceed either because the municipalization effort has been rejected by voters, denied by regulatory commissions, or otherwise abandoned by the municipality during the process. Municipalizations fail to proceed for a variety of reasons, including abandonment by the municipal government after consideration of a feasibility study or rejection by voters after government officials decide to bring the decision to a vote. Municipalization efforts have also been abandoned if costs and time necessary to complete the effort greatly exceed original estimates. 3 Feasibility studies performed on behalf of municipalities frequently underestimate both the time and cost of completing municipalization efforts that do not have the cooperation of the existing utility service provider.

3 In the case of Las Cruces, New Mexico, in 1991, the consultant projected it would cost the city $13 million to $26 million to acquire the electric distribution system. In 1999, Las Cruces abandoned its takeover effort after the costs escalated to over $105 million.

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FIGURE 1: UNITED STATES MUNICIPALIZATION EFFORTS: 2000–2019

Municipality Utility Year Status State Sloan, NY New York State Gas & Electric 2000 Referendum failed NY Las Cruces, NM El Paso Electric Company (EPE) 2000 Abandoned NM Lakewood, NY Niagara Mohawk 2000 Abandoned NY Lakewood, WA Puget Sound Energy 2000 Defeated in Council WA Watford City, ND Montana Dakota Utilities 2001 Referendum failed ND San Francisco, CA Pacific Gas & Electric Company 2001 Referendum failed CA Wichita, KS Western Resources 2001 Abandoned KS Hermiston, OR Pacific Power & Light 2001 Completed OR Village of Hamburg, NY New York Gas & Electric 2001 Abandoned NY Wagner, SD Northwestern 2002 Rejected by Voters SD Oakland, CA Pacific Gas & Electric Company 2002 Abandoned CA Saint Henry, OH Dayton Power & Light, Midwest Electric 2002 Abandoned OH Hercules, CA Pacific Gas & Electric Company 2002 Completed (sold back to PG&E in CA 2014) Corona, CA Southern California Edison 2003 Abandoned by City Council CA Casselberry, FL Progress Energy Florida 2004 Abandoned FL Chula Vista, CA San Diego Gas & Electric 2004 Abandoned CA Clackamas, OR Portland General Electric Co. 2004 Abandoned OR Rancho Cucamonga, CA Southern California Edison 2004 Completed CA Moreno Valley, CA Southern California Edison 2004 Completed CA San Marcos, CA San Diego Gas & Electric 2004 Abandoned CA Pueblo, CO Aquila 2005 Defeated in Council CO Fairfield, IA Alliant Energy Corp. 2005 Abandoned IA Winter Park, FL Progress Energy Florida 2005 Completed FL Cerritos, CA Southern California Edison 2005 Completed CA Oregon Mutual Utility Development Portland General Electric Co. 2005 Rejected by Governor OR Maitland, FL Progress Energy Florida 2005 Rejected by City Council FL Iowa City, IA MidAmerican Energy 2005 Rejected by Voters IA Belleair, FL Progress Energy Florida 2005 Rejected by Voters FL Island Power, Pittsburg, CA Former Military Base 2006 Completed CA Yolo Country, CA Pacific Gas & Electric Company 2006 Rejected by Voters CA City of Paris, IL Ameren Illinois 2007 Abandoned IL Titonka, IA Interstate Power & Light Co. 2007 Abandoned IA City of Atka Andreanof Electric Corp. 2008 Completed AK Everly, IA Interstate Power & Light Co. 2008 Rejected by Iowa Utilities Board IA Kalona, IA Interstate Power & Light Co. 2008 Rejected by Iowa Utilities Board IA Rolfe, IA Interstate Power & Light Co. 2008 Rejected by Iowa Utilities Board IA Terril, IA Interstate Power & Light Co. 2008 Rejected by Iowa Utilities Board IA Wellman, IA Interstate Power & Light Co. 2008 Rejected by Iowa Utilities Board IA San Francisco, CA Pacific Gas & Electric Company 2008 Rejected by Voters CA Skagit County, WA Puget Sound Energy 2008 Rejected by Voters WA Whidbey Island, WA Puget Sound Energy 2008 Rejected by Voters WA Marin Energy Authority Pacific Gas & Electric Company 2010 Abandoned (CCA instead) CA City of Egegik Egegik Light & Power Company 2012 Completed AK South Daytona, FL Florida Power & Light Co. 2012 Rejected by Voters FL Thurston County, WA Puget Sound Energy 2012 Rejected by Voters WA Jefferson County, WA Puget Sound Energy 2013 Completed WA City of Klamath Falls, OR PacifiCorp 2013 Abandoned OR Santa Fe, NM PNM Resources Inc. 2013 Considering NM Minneapolis, MN Xcel Energy Inc. 2013 Abandoned MN Cape Coral, FL LCEC 2014 Abandoned FL Island of Maui, HI Hawaiian Electric Industries 2015 Considering HI Millersburg, Oregon PacifiCorp 2015 Rejected by Voters OR DC Public Power Pepco 2015 Abandoned DC California Electrical Utility District PG&E, SDG&E SCE 2015 Abandoned CA City of Klamath Falls, OR PacifiCorp 2016 Considering OR Bainbridge Island, WA Puget Sound Energy 2017 Abandoned WA City of Destin, FL Gulf Power 2017 Considering FL Boulder, CO Xcel Energy Inc. 2017 Approved CO Pueblo, CO Black Hills Energy 2018 Considering CO Decorah, IA Interstate Power & Light 2018 Considering IA Davis, California Pacific Gas & Electric Company 2018 Abandoned (CCA instead) CA

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Municipality Utility Year Status State Pittsburg, KS Evergy 2018 Considering KS San Francisco, CA Pacific Gas & Electric Company 2019 Considering CA Source: Data derived from various news publications and SNL Financial.

ACQUISITION OF THE UTILITY The acquisition of one or more investor-owned electric utilities for the purposes of establishing a public power agency would likely be completed through a condemnation proceeding. Fair market value, not book value, has historically been the standard for the acquisition of utility property through condemnation. In a transaction such as is contemplated in the State of Maine, this would require the acquisition of the entirety of the investor-owned utilities. Market value for the entire utility operations would likely be determined based on the recent market multiples for utility mergers, discounted cash flow analysis, or in the case of Emera Maine, the value recently offered by ENMAX. In addition to the cost of acquiring the utilities, Maine would also incur costs associated with executing the transactions (e.g., legal, consulting, banking). In addition to the acquisition of the investor-owned utilities in Maine, there would be various additional costs that would need to be incurred, including legal costs and underwriting costs, necessary to issue debt to finance the acquisition costs and fund the start-up efforts that prepare the public utility to exercise its responsibilities.

FIGURE 2: COSTS OF MUNICIPALIZATION

Start up Cost Categories Costs Transaction 5% Acquisition Costs: Costs to acquire the Costs investor-owned utility at market value. 2% Startup Costs: Costs to begin operation as a municipal utility, including development of an Authority or the contracting of a third party to run the Public Power Authority.

Transaction Costs: Costs to execute the transaction, including underwriting and Acquisition debt issuance costs, as well as legal costs. Costs 93%

Acquisition Costs Transaction Costs Start up Costs

Tax-exempt debt is typically not allowed for financing the acquisition of utility property from an investor-owned utility. Thus, while a public utility may be 100% financed with debt, the financing terms would likely be based on similar taxable bond rates that could be obtained by an investor- owned utility. Consequently, the acquisition cost of the utility assets at a market rate that reflects a multiple of the value of the net utility plant will likely offset any benefit to the public power agency associated with acquiring the utility solely with debt. A JP Morgan analysis of 10-year “A” tax-exempt yields and 10-year “A” taxable yields from 2009 to 2019 suggest an average spread between the two

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bonds of 1.24 percent, with the tax-exempt bonds fluctuating between 3.85 percent and 8 percent, and the non-tax-exempt fluctuating between 3 and 6 percent over this period. Figure 3 illustrates the total return for a hypothetical investor-owned utility with a net utility plant value of $1 billion as compared to the debt service of a public power agency acquiring that same utility. As shown, the utility’s weighted average cost of capital reflects both debt and equity financing. When that weighted average cost of capital is applied to the utility’s net plant (assumed to be equivalent to the utility’s regulated rate base), the total annual return, including both interest expense to cover debt service and a return on equity for shareholders, is approximately $95.4 million. In comparison, a public power agency would need to acquire the entire investor-owned utility. Based on recent acquisitions, it is assumed for purposes of the illustration that the acquisition price is 2.0 times the net book value of the utility assets, which results in an acquisition price of $2.0 billion. Assuming that the public power authority would finance the transaction with 100% debt, using revenue bonds at an interest rate of 5%, the resulting debt service would be $100 million – which exceeds the total annual return recovered in rates when the assets are owned by the investor-owned utility (i.e., cost of capital).

FIGURE 3: COMPARATIVE FINANCING COSTS OF INVESTOR-OWNED UTILITY VS. PUBLIC POWER OPERATION

In addition to the financing costs incurred to acquire the assets, the ongoing operation of the public utility is also a significant cost consideration. In the case of the acquisition that is currently

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contemplated in the Maine legislation, it would be necessary to either establish an authority/agency to manage the utility or would require contracting with a third party to operate the utility. The additional operating costs resulting from long-term contracting to manage the utility may increase the overall operating cost above the costs experienced by customers today.

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CASE STUDIES ON MUNICIPALIZATION

The majority of the large public power agencies were established in the 1930’s and 1940’s, however, the most recent municipalizations are instructive as to the challenges that can occur in the formation of a new municipal electric utility. In particular, it is often the case that acquisition and initial operating costs are understated. This results in higher than expected annual operating costs of the municipal electric utility and weakening savings opportunities, at least in the early years.  Boulder, Colorado: Primary reason for municipalization was to have control over power supply and to move towards renewable resources. After 15 years of effort and significant costs incurred, while the Commission approved the asset transfer, the buyout cost is still not finalized and per an agreement with Xcel, the city must again vote on municipalization.

 Winter Park, Florida: Acquisition costs escalated from an original estimate of $16 million to nearly $50 million by the time the takeover of the local electric system was completed.

 Jefferson County, Washington Public Utility District: Initial feasibility study for the acquisition of Puget Sound Energy’s electric assets estimated an acquisition cost of $47 million, which was less than half of the final acquisition cost of $103 million, excluding start- up expenses.

CITY OF BOULDER Boulder’s municipalization efforts to acquire Xcel Energy’s distribution system within the city started about a decade and a half ago and remain unresolved. The city currently has an expected municipal utility start date of 2024, though buyout costs remain uncertain. After settling with Xcel in 2019 over the city’s formation of an electric utility, Boulder agreed to dissolve its electric utility, but will vote again in 2020 on whether to pursue formation of an electric utility. In addition, while a district court dismissed the city’s condemnation filing, the City of Boulder has appealed the decision, and officials have continued to pursue the condemnation process through the Colorado Public Utilities Commission (“CPUC”). The CPUC issued an Order in October 2019, approving the transfer of assets outside substations from Xcel to Boulder, including poles, underground and overhead transformers, and primary circuits. For assets inside substations, Boulder and Xcel will need to reach an agreement on these assets, or Boulder will need to build its own substations. Pursuant to § 40-5-105, C.R.S., Boulder and Xcel must still file an application in a separate proceeding for final Commission approval of the asset transfer, prior to a change in control.4

4 Colorado Public Utilities Commission, Decision No. C19-0874, Proceeding No. 15A-0589E, October 10, 2019. City of Boulder, Colorado. “Local Power News.” Accessed October 31, 2019. Available at: https://bouldercolorado.gov/local-power/latest

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FIGURE 4: TIMELINE OF BOULDER MUNICIPALIZATION EFFORT

City did not City issued renew Xcel City Council Voted Commission District Court preliminary franchise in favor of District allowed dismissed municipalizati agreement municipalization Court Boulder Boulder’s on feasibility going forward; dismissed to proceed condemnation study voters approved Xcel’s with filing, and lawsuit $214mm spending municipaliz Boulder ation for system appealed

2002 2004 2006 2008 2010 2012 2014 2016 2018 2019

City implemented Xcel citywide carbon tax City Council filed City issued final approved moving City adopted lawsuit municipalization forward with resolution feasibility study acquisition supporting Colorado Court of Kyoto Protocol Appeals overturned 2015 decision Boulder and Xcel settled lawsuit (requires Boulder to dissolve utility and city to vote in 2020 whether to pursue municipalization)

CPUC issued order approving asset transfer to Boulder

Escalation of Municipalization Costs

Boulder’s estimated municipalization costs have escalated considerably throughout the process, rising from less than $140 million in the 2005 preliminary feasibility study to between $300 and $337 million by current estimates depending on the range of separation costs to be incurred. In addition, these 2018 cost estimates for municipalization do not include costs for stranded investments, originally estimated at $26 million (in 2018 dollars). While the city and Xcel remain far from

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determining acquisition costs for the system, Xcel and the City estimate buyout costs could reach $900 million.5,6

Escalation of Legal Costs

Given the protracted negotiation period and ongoing court battles, as shown in Figure 5, estimates for legal costs have risen dramatically over the past several years. Whereas the city’s 2005 preliminary feasibility study did not list a figure for legal costs, the city’s 2011 final feasibility study included $3 million in legal fees. However, as of 2017, Boulder had already incurred $18 million in legal fees associated with its municipalization efforts, and city voters had approved another $17 million to be spent over the next five years, for a total of $35 million by 2022.7

FIGURE 5: BOULDER MUNICIPALIZATION LEGAL COSTS TO DATE

Boulder Municipalization Legal Costs to Date 40 Incurred Projected (City-Approved) 35

30

25 ($mm) 20 2011 Feasibility Study (Expected) 15

10

5

0 2005 2011 2016 2017 2022

5 https://bldrfly.com/features/boulders-municipalization-effort-explained/ 6 https://www.bizjournals.com/denver/news/2017/04/18/boulder-council-votes-to-move-forward-on- city.html 7 R.W. Beck. “Preliminary Municipalization Feasibility Study: City of Boulder, Colorado.” October 2005. Robertson-Bryan, Inc. “Boulder Municipal Utility Feasibility Study.” August 16, 2011. Jaffe, Mark. “Boulder wanted its own electric utility. Does it still?” The Denver Post. October 27, 2017. Available at: https://www.denverpost.com/2017/10/27/boulder-wanted-its-own-electric-utility-does-it-still/; Meltzer, Erica. “Boulder’s spending on municipal utility tops $10 million.” March 5, 2016. Available at: https://www.dailycamera.com/2016/03/05/boulders-spending-on-municipal-utility-tops-10-million/; Boulder Beat. “Boulder, Xcel haggling over assets. $20M spend on muni so far.” March 2, 2019.

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WINTER PARK, FLORIDA Winter Park formed an electric utility in 2005 by acquiring the local electric distribution assets of Progress Energy, exercising a right-to-purchase clause that is unique to Florida franchise conditions. Despite agreeing to compensation being determined through arbitration rather than litigation, the effort took six years. When initially setting municipal electric rates, the city held the electric rates at the same level as Progress Energy. While the city represented in its bond issuance that it expected to make millions of dollars a year, instead the city ended up losing approximately $11 million over the first four years of municipal operation and was placed on credit-watch negative by rating agencies.8 In 2008, Winter Park experienced decreased electric sales and an increase in the cost of bulk power, causing net revenue to decrease below the minimum 1.25 times debt service ratio to 0.73.9 Winter Park has subsequently increased its rates significantly to overcome the cumulative $11 million loss and its failure to comply with its debt covenants.10 The municipal utility in Winter Park is approximately 15 years into its existence, and improvements have been made in the community regarding rates, undergrounding and debt repayment. However, Winter Park has seen significant changes in its rates and rate structure. For example, while residential rates for Winter Park (for a customer using 1,000 kWh) are lower than those of the former utility provider (i.e., Duke Energy Florida), Winter Park has changed the rate design significantly, increasing the residential customer charge substantially (from $9.55/month in June 2017 to $16.98/month as of October 2019, or a 78% increase). This was recently criticized by an editorial in the Orlando Sentinel that cited Winter Park’s changes as disproportionately affecting low-income customers and encourages customers to be less energy efficient.11

PUBLIC UTILITY DISTRICT NO. 1 OF JEFFERSON COUNTY Jefferson County Public Utility District No. 1 (“JPUD”) acquired the local electric distribution assets and service area of Puget Sound Energy (“PSE”) in 2013. This was approximately five years after the acquisition was originally approved by the electorate and at an acquisition cost of approximately $110 million—or more than double original estimates. The acquisition was a negotiated process and driven by JPUD’s desire to obtain local control over electric service. JPUD was successful in securing power from Bonneville Power Authority (“BPA”), but its retail electric distribution rates currently exceed the rates charged by PSE. JPUD initiated the municipalization process in 2008, contracting for a preliminary feasibility study on electric system acquisition. The feasibility study provided a 10-year comparison of the cost of

8 City of Winter Park, Florida Bond Issuance Prospectus, Electric Revenue Bonds, Series 2005A and Series 2005B, Initial Auction Date June 6, 2005, C-30. 9 City of Winter Park, Florida Comprehensive Annual Financial Report, at 25. 10 City of Winter Park, Florida Bond Issuance Prospectus, Electric Revenue Bonds, Series 2005A and Series 2005B, Initial Auction Date June 6, 2005, at C-30. 11 “Winter Park’s electricity price hikes show the city hasn’t planned for a more energy-efficient city,” Orlando Sentinel, October 8, 2019.

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continued electric service with PSE relative to the cost of service for a PUD. The study assumed that JPUD would be able to acquire PSE’s assets for approximately $47.2 million, with total financing requirements of $66 million including initial acquisition costs, separation, start-up and legal costs, working capital and financing expenses.12 The study concluded that JPUD could provide service beginning in 2011 at rates that were slightly higher than PSE’s rates for the first three years of operation, but that rates would decrease noticeably in the fourth year, when low-cost BPA power became available. The study further noted that (1) if the acquisition year was assumed to line up more closely with the BPA power supply, and (2) if the parties relied on “more realistic” acquisition costs for the PSE assets and different financing assumptions, the acquisition would result in lower rates for PUD electric service in all 10 years of the study.13 However, the actual acquisition and transaction costs incurred by JPUD were substantially higher than projected in the feasibility study. 14 Through a negotiated sale agreement with PSE, JPUD’s purchase of PSE’s asset was completed in 2013 at a sale price of $109.3 million, or approximately 2.3 times the $47.2 million projection provided in the feasibility study.15 In addition, actual operating costs and resulting electricity rates under JPUD operation have been higher than projected, altering the rate comparison with PSE originally estimated in JPUD’s feasibility analysis. JPUD’s initial rates for the 2013–2016 period remained comparable with PSE’s 2013 rates. However, PSE increased rates 1.4% per year over the past five years,16 while JPUD implemented two rate increases in 2017. For residential customers, the rate increases totaled 6.3% in 2017 and 4.5% in 2018.17 These rate increases are of note, particularly given that JPUD obtains all its power purchases from the Bonneville Power Administration at rates well below average market prices. Despite such access to this low-cost resource, which most new municipal utilities are not afforded, JPUD still experienced significant rate increases.

12 Preliminary Feasibility Study (D. Hittle & Associates, Inc.), Public Utility District No. 1 of Jefferson County Electric System Acquisition, October 24, 2008, at 21. 13 Id., at 5. 14 JPUD did not rely on D. Hittle & Associates, Inc. for purposes of its negotiations with PSE. Rather, JPUD retained Brown & Kysar, Inc. to do a subsequent analysis. Brown & Kysar’s predicted acquisition cost varied depending upon stated assumptions but ranged from $58 million to $83 million. WUTC Docket No. UE-132027 (prefiled direct testimony of Karl R. Karzmar). 15 WUTC Docket No. UE-132027, at 1. 16 Concentric recognizes that PSE recently filed with the WUTC, requesting a 3.2 percent rate increase. The outcome of that case will not be determined for several months. Therefore, the rate comparison assumes that this rate increase is adopted by the WUTC. 17 Based on residential kWh sold and residential revenues from RUS Form 7. Financial and Operating Report Electric Distribution, 2016-2018.

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PRIVATIZATIONS

While municipalization has generally been unsuccessful since 2000, there have been more frequent occurrences of privatization (i.e., the sale of municipal assets to investor-owned utilities). Figure 6 summarizes the municipal electric utilities that have recently been acquired by investor-owned utilities. The table below includes privatizations of municipal electric utilities. However, this section also discusses privatization of an electric cooperative in Maine.

FIGURE 6: RECENT ELECTRIC UTILITY PRIVATIZATION ACTIVITY

Utility Municipality Municipalization Year Privatization Year American Electric Power Elk City, OK 2004 2010 Company, Inc. Indiana Michigan Power City of Fort Wayne, IN Pre-2000 2011 Company Central Vermont Public Readsboro, VT Pre-2000 2011 Service Corp. Pacific Gas & Electric Hercules, CA 2002 2014 Company Rocky Mountain Power Eagle Mountain City, UT Pre-2000 2015 Florida Power & Light Co. Vero Beach, FL Pre-2000 2018

COMPLETED PRIVATIZATIONS

Elk City, OK Fuel rate increases in Elk City spurred a municipalization effort that began in 2002. The initial effort failed a vote in December 2002, but a small portion of the community was later municipalized in 2004, taking ownership of the assets that served eight customers from Public Service Company of Oklahoma (“PSO”). However, the city’s efforts to stabilize electricity prices under municipal ownership proved difficult, and Elk City issued a request for proposals in May 2009 for the sale of its municipal electric system. Elk City chose PSO’s proposal in July 2009 and the sale was completed in February 2010 with PSO acquiring a total of 69 customers through the privatization.18

City of Fort Wayne, IN Since the 1970s, Indiana Michigan Power Company (“IMPC”) had leased the electric distribution assets in the City of Fort Wayne. In 2010, the parties were considering renewal of the lease or full

18 Jackson, Ron. “Post-election fuel rate hike causing stir: Retroactive increase upsets some residents.” The Oklahoman. January 4, 2003. Available at: https://oklahoman.com/article/1910287/post-election-fuel- rate-hike-causing-stirbrretroactive-increase-upsets-some-residents; American Public Power Association. “Public power = local control.” Available at: https://www.publicpower.org/blog/public-power-local- control; Public Service Company of Oklahoma. “PSO purchase of Elk City electric system is complete.” February 26, 2010. Available at: https://www.psoklahoma.com/info/news/viewRelease.aspx?releaseID=816

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ownership by either the city or IMPC. After months of negotiations, the city and IMPC signed an agreement for the IOU to take control of the electric system, citing an end to expensive litigation as a key benefit of the agreement. IMPC agreed to pay the city $5 million upfront and $34.2 million spread over multiple years, and the transfer was completed in 2011. A significant driver for the sale was that the city would gain access to the City Light Trust Fund, established over 35 years earlier with an approximate value of $36 million, as well as an overfunded pension obligation of $700,000. In addition, IMPC paid $39 million over 15 years to the city for its electric distribution assets. This privatization example highlights the often conflicting priorities faced by cities with MEUs. In the end, the city determined funds were best spent elsewhere than on continuing service through its MEU.19

Readsboro, VT The Readsboro MEU experienced significant rate increases in the late 2000s, which resulted in the municipal utility ultimately putting the utility up for sale. Prior to the sale, the city had voted three times on whether to sell the electric utility assets. The municipality’s electric distribution assets were sold in 2011 to Central Vermont Public Service Corporation (“CVPS”) in an effort to reduce rates. The proceeds from the sale to CVPS were to be used by the municipality for power restoration costs resulting from an ice storm, with the remaining balance available for town use.

The Readsboro MEU governing body approved several large increases in rates prior to the sale of its assets. In 2007, the Readsboro MEU received a 22% rate increase (after requesting a nearly 27% increase) and a 31% increase again in 2009. Readsboro’s rate increases were largely to update accounting procedures and cover capital improvements. In comparison, CVPS’s rates increased by just over 2% in 2007 and by 6% in 2010. See chart below to the left. Despite the rate increases, the MEU still reported negative net utility operating income on a per- customer basis, indicating that the MEU’s costs still exceeded revenue on a per-customer basis. As shown in the chart below to the right, Readsboro’s operating income loss reached $284/customer in 2009. If the MEU had not been sold, the municipality was expecting a further 28% rate increase to make up for operating losses. This financial instability contrasts with the stable operating income per customer achieved by CVPS (approximately $120-$140/customer) during this same period.20

19 S&P Global Market Intelligence, “AEP to own system, serve full Fort Wayne, Ind., territory under settlement with city” October 29, 2010. City of Fort Wayne. “Light Lease Settlement.” December 8, 2010. Available at: https://www.cityoffortwayne.org/144-mayors-office/321-light-lease-settlement.html; City of Fort Wayne, IN. “City Light Lease Settlement Announcement.” Available at: https://www.cityoffortwayne.org/images/stories/mayors_office/docs/aep_major_term.pdf 20 S&P Global Market Intelligence. Whitcomb, Keith. “CVPS purchases Readsboro Electric Dept.” Brattleboro Reformer. November 18, 2010. Available at: https://www.reformer.com/stories/cvps-purchases- readsboro-electric-dept,114286; Whitcomb, Keith. “PSB approves sale of Radsboro Electric Light Department to CVPS.” The Berkshire Eagle. July 18, 2011. Available at: https://www.berkshireeagle.com/stories/psb-approves-sale-of-readsboro-electric-light-department-to- cvps,245513; Rutland Herald Online. “Readsboro retains electric company.” March 3, 2009. Available at: https://www.rutlandherald.com/news/local/readsboro-retains-electric-company/article_230a690e- eb9d-51b8-9bd9-df450e66164b.html; Vermont Department of Public Service. “Vermont Department of Public Service Biennial Report: July 1, 2006-June 30, 2010.” July 2011.

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Net Utility Operating Income/Customer $200 $150 $100 $50 $0 -$50

-$100 ($/customer) -$150 -$200 -$250 -$300 Readsboro CVPS -$350 2006 2007 2008 2009

Hercules, CA In 2002, Hercules municipalized the electric assets of Pacific Gas and Electric Company (“PG&E”) citing the opportunity to increase revenue. Once completed, the city began purchasing wholesale power at market prices, promising customers that it would be able to do so at competitive rates while making profits that would flow to the general fund; however, the scenario was based on assumptions of growth in Hercules that did not materialize. Instead, operating expenses greatly outweighed revenues and the city was forced to continually subsidize the MEU from the city’s general fund. The city also had difficulty with its utility investments, having canceled a planned substation that cost customers millions. Around the same time, Standard & Poor’s downgraded two of the city’s bonds to junk or near-junk and placed the city on credit watch negative. In June 2012, due to cost escalation and the operational losses that increased MEU customer rates, a measure to sell the municipal utility was approved by 77% of voters. The electric distribution system was subsequently sold back to PG&E in 2014, with the accumulated capital and operating losses just through 2011 estimated to be $9 million.21

Eagle Mountain City, UT In November 2014, citizens in Eagle Mountain City voted to sell the electric and gas MEUs, a transaction that had been in negotiations for nearly a year. The city had concerns surrounding its debt from establishing the MEUs and saw proceeds from the sale as a way to reduce current and

21 Stanfield, Jeff. “Calif. Town votes to sell its small municipal utility to PG&E to meet debt.” S&P Global Market Intelligence, May 29, 2013. East Bay Times, April 16, 2014, “Hercules: Sale of municipal utility ends multimillion-dollar fiasco”. City of Hercules California, Annual Financial Report for the fiscal year ended June 30, 2013, at 54 and 62. Porterfield, Bob. “Hercules Municipal Utility has Drained, Not Charged, City Coffers.” August 12, 2011.

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future debt and enhance the potential for rate stability through increased efficiencies associated with larger IOU ownership and operations. In 2015, Eagle Mountain City sold its electric system to Rocky Mountain Power and sold its gas system to Questar Gas.22

Vero Beach, FL Vero Beach had owned and operated its MEU since 1919. In 2009, a complaint filed against Vero Beach expressed concerns over the MEU’s rates, use of electric utility funds, and customer representation. At that time, driven by poor management decisions, the MEU’s residential rates were approximately 20-30% higher than comparable electric rates of Florida Power & Light (“FPL”), a neighboring IOU.23 Two of the reasons the complaint cited for rate increases were that the city had not conducted a rate and service study since 1991, and the city was relying on the electric utility as significant source of revenue to the general fund. The complaint noted that contributions from the MEU represented over half the city’s entire budget. In addition, the MEU was also criticized for failing to offer energy conservation incentives that were offered by the IOU, and for failing to build up a monetary reserve for future emergencies. A major point of tension was the fact that around 60% of the MEU’s customers lived outside the municipal borders, which was the largest proportion of customers outside the city limits for all municipal utilities in Florida. As a result, these customers felt they were not able to participate in and challenge utility decision making. While there were multiple legislative attempts to address this issue, all of them failed.24

The sustained higher rates and resulting customer complaints prompted the city to pursue privatization. After almost a decade of effort, Vero Beach completed the privatization of its municipal electric utility in 2018, selling the MEU to FPL.

Swan’s Island Electric Cooperative Swan’s Island Electric Cooperative (SIEC) provided power to both Swan’s Island and Frenchboro, located six and eight miles from Mount Desert Island, respectively. Many parts of Maine were once served by small cooperatives like SIEC, but most have merged with Emera or Central Maine Power

22 Gorrell, Mike. “Eagle Mountain sells its electric, gas systems.” The Salt Lake Tribune, March 4, 2015. https://archive.sltrib.com/article.php?id=2250287&itype=CMSID; Allen, Sam. “Eagle Montain City Utility Scandal.” www.eagleshare.org. February 9, 2013. Eagle Mountain City. “Adopted Operating Budget: Fiscal Year 2015-2016.” Rocky Mountain Power. “Why Rocky Mountain Power wants to serve Eagle Mountain City.” September 12, 2014. Available at: https://www.rockymountainpower.net/about/nr/rmpol/archive/wrmpwtsemcr.html 23 Florida Public Service Commission. “Comparative Rate Statistics.” December 31, 2009. http://www.psc.state.fl.us/Files/PDF/Publications/Reports/General/Comparative/December%2031,% 202009.pdf; FL PSC Docket No. 20090524. Complaint of Stephen J. Faherty and Glenn Fraser Heran against the City of Vero Beach for unfair electric utility rates and charges, December 3, 2009, at 2-4. 24 FL PSC Docket No. 20090524. Complaint of Stephen J. Faherty and Glenn Fraser Heran against the City of Vero Beach for unfair electric utility rates and charges, December 3, 2009, at 2-4. FL PSC Docket No. 20170236. Final Order No. PSC-2018-0566-FOF-EU. November 30, 2018, at 6. FL PSC Docket Nos. 20170235-EI, 20170236-EU. Order No. PSC-2018-0336-PAA-EU. July 2, 2018, at 2.

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(CMP), rates for which average $0.16 per kWh. SIEC, by contrast, was charging more than double that at $0.38 per kWh. While SIEC paid similar rates for generation as compared to mainland residents, the delivery costs drove the higher costs for SIEC. As a result, SIEC searched for an alternative for almost a decade, first assessing renewable energy potential, collaboration with other islands, and cutting operating expenses. However, economies of scale became a crucial factor. A large 2014 SIEC rate increase included a Commission stipulation that SIEC would assess feasibility of a merger with Emera. The PUC first voted 2-1 against the $2.5 million merger, based on the anticipated impacts of the merger on Emera’s larger customer base, which included over SIEC debt of $614,000. Two months later, the Commission approved a final merger price wherein the former SIEC customers would repay the $614,000 in debt over five years through a $19.30 monthly surcharge. The initial offer covered SIEC’s existing debt, which the Commission rejected, arguing that Emera’s existing customers should not pay for SIEC’s debt. SIEC then determined that its residents would pay back the debt through a $19.30 monthly surcharge over five years to cover about $614,000 of the acquisition cost. SIEC customers were expected to see a $20 drop in their electricity bills after the merger, with fixed monthly fees dropping from about $46 to $27.25

POTENTIAL PRIVATIZATION

Jacksonville, FL Jacksonville Electric Authority (“JEA”), which is the current MEU for Jacksonville, Florida, is currently exploring options to privatize its system. The decision is based on low sales driven by efficiency gains and distributed generation, which has led to rate increases, with more expected in the future. In November 2017, a member of the JEA Board of Directors originally suggested considering privatization, but progress on the matter paused for most of 2018 due to executive turnover. In May 2019, JEA staff warned the Board of Directors of lower sales and noted that pursuing privatization would be the best way to avoid layoffs and rate increases. According to the staff projections, JEA could face a $2.3 billion cash shortfall in 2030 that could result in significant rate increases and/or the need to eliminate contributions to the city general fund. In addition, there was concern that the

25 Island Institute. “PUC vote raises question: Are we all Swan’s Island.” January 26, 2017. Available at: http://www.islandinstitute.org/working-waterfront/puc-vote-raises-question-are-we-all-swans-island; Bangor Daily News. “One of the country’s smallest electric co-ops dissolves on Maine island.” March 16, 2017. Available at: https://bangordailynews.com/2017/03/16/news/state/maine-islanders-vote-to- give-up-local-control-of-electricity/; Bangor Daily News. “Regulators deny Maine islands’ attempt to lower electric bills.” January 18, 2017. Available at: https://bangordailynews.com/2017/01/18/news/hancock/regulators-deny-maine-islands-attempt-to- lower-electric-bills/; Docket No. 2016-00209. Joint Petition. State of Maine Public Utilities Commission. September 1, 2016. Docket No. 2013-00534. State of Maine Public Utilities Commission. “2016 Annual Report.” February 1, 2017. Available at: https://www.maine.gov/mpuc/about/annual_report/documents/2016AnnualReportFinalJanuary19201 7.pdf; State of Maine Public Utilities Commission. “Order Approving Stipulation.” March 13, 2017.

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utility may face a significant layoff of utility staff. The cash gap was projected due to expected increasing operating expenses and decreasing revenues.26

JEA underestimated the effect of energy efficiency and other trends on its business. Specifically, the utility experienced flat to declining growth between 2007 and 2017 largely due to energy efficiency savings. The shortfall in JEA’s revenue projections was $1.4 billion in free cash flow. Additionally, JEA’s contributions to the city would have been $80 million per year higher under original forecasts. Distributed generation is also poised to continue to affect the utility, as JEA is currently losing more than $2.5 million in annual net income to distributed generation, and further disruption is expected as customer-owned distributed generation plus storage is projected to be at cost parity with JEA’s generation by 2025. JEA has increased rates 71% since 2006 and has eliminated 407 jobs in response to these trends.27

A formal process to solicit interest in the privatization of JEA was launched on August 5, 2019. JEA is looking for potential buyers to demonstrate how they will embrace industry changes, add new revenue streams, and “future-proof” the business. Proposals were due by September 30, 2019 and JEA has narrowed the list of candidates to nine parties. The nine parties include three investor-owned utilities (Duke Energy Corp., Emera Inc., and NextEra Energy Inc.), a separate bid from Emera with Bernhard Capital Partners Management LP and Suez SA, American Public Infrastructure LLC, American Water Works Co. Inc., IFM Investors Pty Ltd., Macquarie Infrastructure & Real Assets Inc., and a ninth confidential party. JEA expects to receive revised replies from the parties by the end of November 2019 with an evaluation to take place through the first quarter of 2020. 28

26 Bermel, Colby. “Jacksonville, Fla., utility board tables privatization activities.” S&P Global Market Intelligence. May 15, 2018; Mendenhall, Mike. “JEA will look at ways to privatize the city-owned utility.” Jax Daily Record. July 23, 2019. Available at: https://www.jaxdailyrecord.com/article/jea-will-look-at- ways-to-privatize-the-city-owned-utility; JEA. “Board Meeting Agenda and Package. Establishing a Baseline: “Status Quo.”” May 28, 2019, at 25. Available at: https://www.jea.com/Events/Board_Meetings/2019_05_28_Board_Meeting_Package/; Meyers, Ellen. “Fla. utility JEA to explore privatization again, other ownership options.” S&P Global Market Intelligence. July 23, 2019; JEA. “Florida’s Largest Municipally-Owned Utility Formally Launches Competitive and Open Solicitation Process to Transform Northeast Florida.” August 2, 2019. Available at: https://www.jea.com/About/Media_Relations/2019_08_02_Invitation_to_Negotiate_ITN_127- 19_for_Strategic_Alternatives/ 27 JEA. “Board Meeting Agenda and Package. Establishing a Baseline: “Status Quo.”” May 28, 2019, at 17-22. Available at: https://www.jea.com/Events/Board_Meetings/2019_05_28_Board_Meeting_Package/ 28 Meyers, Ellen and Cotting, Ashleigh. “JEA solicitation seeks strategies to ‘future-proof’ Fla. Utility.” S&P Global Market Intelligence, August 13, 2019; Meyers, Ellen. “JEA advisers lay out utility sector changes driving ownership solicitation.” S&P Global Market Intelligence, October 22, 2019.

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PUBLIC POWER AUTHORITIES

The majority of the largest municipal utilities were established decades ago, including eight during the 1930s alone at a time when many rural areas were becoming electrified. The average establishment date for the largest 20 municipal utilities is 1934, or 85 years ago. This contrasts with the current market, where municipal utilities must acquire assets from investor-owned utilities and incur significant additional startup costs. Several of the largest public power utilities also benefited from cheap, federal-funded hydropower. For example, of the largest 20 municipal utilities in the U.S., 9 are located near the BPA in the Pacific Northwest or the Tennessee Valley Authority (“TVA”) in the Southeast.29 Access to these federally-funded generation facilities provides these municipal utilities with power rates that are well below current market rates.30 Unfortunately, Maine does not have access to similar federally-funded resources.

29 Includes Seattle City Light, Snohomish County PUD No. 1, PUD No. 1 of Cowlitz County, and Tacoma Public Utilities in the Pacific Northwest and Memphis Light, Gas and Water Division, Nashville Electric Service, the City of Chattanooga, the City of Knoxville, and Huntsville Utilities in the Southeast. 30 While this report does not specifically address reliability, there is no evidence that Concentric is aware of that suggests that the reliability of public power authorities is stronger than the reliability provided by investor-owned utilities.

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FIGURE 7: LARGEST PUBLIC POWER UTILITIES AND YEAR OF ESTABLISHMENT

Largest 20 Public Power Utilities Establishment Year of Largest 20  Salt River Project, AZ (1937)  LADWP, CA (1916) TVA (1933)  CPS Energy, TX (1942) BPA (1937)  NYPA, NY (1931)  LIPA, NY (1985)  Memphis Light, TN (1939)  Austin Energy, TX (1895)  JEA, FL (1968)  Nashville, TN (1939)  Sacramento PUD, CA (1946)  Omaha PPD, NE (1946)  Seattle City Light, WA (1904)  Santee Cooper, SC (1934)  Snohomish PUD (1949)  Orlando Utilities, FL (1923)  City of Chattanooga, TN (1935)  City of Knoxville, TN (1939)  Huntsville Utilities, AL (1940)  Cowlitz PUD, WA (1936)  Tacoma, WA (1903)

BONNEVILLE POWER ADMINISTRATION BPA is a nonprofit federal power marketing administration based in the Pacific Northwest. BPA markets power from 31 federal hydroelectric projects in the northwest in addition to one nonfederal nuclear plant and several smaller nonfederal projects.31 Figure 8 shows that the majority of BPA’s electricity is generated using hydroelectric resources, which are the lowest cost generation sources historically providing power at well below market rates. Figure 9 identifies the Public Power Authorities that receive generation from BPA.

31 https://www.bpa.gov/news/AboutUs/Pages/default.aspx

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FIGURE 8: BONNEVILLE POWER ADMINISTRATION GENERATION RESOURCE PORTFOLIO

FIGURE 9: BONNEVILLE POWER ADMINISTRATION AND SELECTED LARGE PUBLIC POWER UTILITIES

TENNESSEE VALLEY AUTHORITY Tennessee Public Power Association is run by the TVA and provides power to consumer-owned electric utilities operating in the Tennessee Valley. TVA was formed in the 1930s and has relied on federal funding to develop power sources since that time. TVA provides wholesale electric power to the TVA region. Figures 10 and 11 indicate TVA’s generation portfolio and the area and municipalities served.

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FIGURE 10: TENNESSEE VALLEY AUTHORITY GENERATION RESOURCE PORTFOLIO32

FIGURE 11: TENNESSEE VALLEY AUTHORITY AND SELECTED LARGE PUBLIC POWER UTILITIES

As a result of the access to low cost wholesale power, the rates in 2017 for the nine public power utilities near either Bonneville or TVA were between 20% to 39% below the average rates for municipal utilities (including state and political subdivisions). In addition, given the average age of most of these public power utilities and the access to inexpensive hydropower, the top 20 public power utilities had rates that were between 11% to 33% below the average municipal rates.

32 TVA FY 2018.

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PUBLIC POWER VS. INVESTOR-OWNED UTILITY RATE COMPARISON As discussed, most successful public power authorities have electric systems that have been constructed over time and have had access to low cost power supply. However, more recent municipalizations have not resulted in similar cost savings, even with access to public power. Figure 12 provides a residential rate comparison of three electric providers in Washington (i.e., PSE, JPUD and Snohomish Public Utility District). While Snohomish PUD is the lowest cost supplier, it was established in 1947 with access to low cost BPA hydroelectric generation. JPUD, which was established in 2013, is the highest cost electric provider, even with access to BPA, and has higher electric rates than Puget Sound Energy, the investor-owned utility from which the JPUD assets were acquired.

FIGURE 12: RESIDENTIAL RATE COMPARISON OF WASHINGTON STATE ELECTRIC UTILITIES

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Case Study: LIPA

LIPA was originally created under the Long Island Power Act in 1985 as a state subdivision. Cost and reliability concerns grew over time, punctuated by Superstorm Sandy, after which Long Island customers saw significant delays in power restoration. Key concerns over LIPA included:33  LIPA’s debt costs became an onerous issue and were restructured multiple times as a result. LIPA’s average debt ratio was 137% (double that for comparable large public power utilities) between 2011-2013. In 2014, LIPA reported total debt of $7.6 billion (up 11% over 2010), with projections of $8 billion by 2018.34  Between 2006 and 2012, storm costs (excluding Superstorm Sandy costs) exceeded annual budgets by an average of 239%.

In 2013, the state enacted legislation to stabilize rates, improve service, and improve accountability at LIPA. 35 A 2015 report filed by the New York State Comptroller found that LIPA’s average residential retail rate was 22% higher than the New York median, and 78% above the national median in 2013. 36 LIPA’s commercial retail prices are worse, at 92% above the national median.37 As a result of escalating costs and reliability issues, in 2014, LIPA was forced to select an investor-owned utility to manage its assets, choosing Public Service Enterprise Group. Figure 13 compares LIPA’s power rates relative to other municipal utilities. Between 2008 and 2017, LIPA’s total power rates were, on average, 65% higher than the average for all municipal utilities.38

33 https://www.osc.state.ny.us/press/releases/july15/072415.htm 34 https://www.osc.state.ny.us/reports/pubauth/lipa_by_the_numbers_7_2015.pdf 35 https://www.osc.state.ny.us/press/releases/july15/072415.htm 36 https://www.osc.state.ny.us/press/releases/july15/072415.htm 37 https://www.osc.state.ny.us/reports/pubauth/lipa_by_the_numbers_7_2015.pdf 38 S&P Global Market Intelligence; including political subdivisions and state entities (state entities in U.S. territories excluded).

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FIGURE 13: MUNICIPAL UTILITY RATES (INCL. STATE AND POLITICAL SUBDIVISIONS) VS LIPA

* Includes political subdivisions and state entities (state entities in U.S. territories excluded)

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