2016 - Energy Mergers and Acquisitions Maintain Momentum; Oil and Gas Markets Begin to Climb Back; Will Uncertainty Cloud the Outlook for 2017?

 Page 1 February 15, 2017 TO: CLIENTS AND OTHER FRIENDS OF THE FIRM 2016 – Energy Mergers and Acquisitions Maintain Momentum; Oil and Gas Markets Begin to Climb Back; Will Uncertainty Cloud the Outlook for 2017? Each year around this time we take the opportunity to review the transactions and other significant industry developments over the past year and offer our views on what they may mean for the coming year. Mergers and acquisitions activity in the energy industry during 2016 was below the levels of 2015 and 2014 in most categories, but still substantial. While the Goldilocks environment of 2014 and 2015 did not last through 2016, transaction volume was still a healthy $141 billion, which was just about the average of the past seven years.1 Concerns about rising interest rates, election uncertainty and a general fall-off in utility stock valuations created headwinds that could not be overcome by rising oil prices and a generally stable economy. Other factors may have been a growing mismatch between valuation expectations of buyers and sellers and generally fewer acquisition opportunities. With the extraordinary valuations achieved in several transactions announced during 2015, sellers had high expectations while at least some buyers may have concluded that valuations had reached untenable levels and pulled back a bit. More than half the 2016 activity involved pipelines, midstream companies and MLPs, with $76 billion of announced transactions, down from over $130 billion the year before. Transactions among regulated electric utilities also declined to $19.8 billion from $33.8 billion. Among LDCs, volume declined dramatically to $4.8 billion from more than $18 billion in 2015, when transactions involving AGL Resources and Piedmont Natural Gas Company set a new high-water mark. Even at the reduced level, LDC transaction volume in 2016 was the second highest of any of the past seven years. One category where 2016 volume increased dramatically over 2015 was in transactions involving electric generation assets where volume was $33.5 billion, one of the highest years on record, and well above the $8.1 billion recorded in 2015. This dramatic increase was due in large part to the NextEra/Energy Future Holdings transaction that contributed over $18 billion to the total. Transactions involving renewable generation assets also decreased to $6.6 billion from $8.5 billion in 2015. Key transactions and trends that we see in each of these subsectors are discussed in more detail below. 1 Source: S&P Global, SNL Energy, transactions with announced transaction values of $100 million or more. Contributors: James H. Barkley Brooksany Barrowes Emil Barth Megan Berge Jonathan Bobinger William M. Bumpers Joshua Davidson Michael Didriksen A.J. Ericksen Manny Grillo Jerrod Harrison Thomas Holmberg Marcia Hook Gina Khanna William S. Lamb Luckey McDowell Steven R. Miles Jon Nelsen Jay Ryan Carlos Solé Andrew Stuyvenberg Timothy S. Taylor Martin Toulouse Gregory Wagner Elaine M. Walsh Page 2 As has been the case for over twenty-five years, there are many factors that favor continued consolidation among energy companies in the United States. Scale and diversity are as important as ever. The US energy industry is going through a period of significant change, with many companies facing unprecedented capital expenditures and competitive pressures. Much of our national energy infrastructure is in the process of being rebuilt. Energy policy and consumer preference are driving a shift away from fossil fuels toward renewable resources, although there may be some swing of the pendulum back toward fossil fuels under the Trump Administration. In many instances new renewable generation requires substantial investments in new highvoltage transmission lines to get the power to load centers. At the distribution level for regulated utilities, both electric and gas companies are in the process of replacing and upgrading much of their local infrastructure to improve both safety and reliability. Finally, what appears to have become a stable supply of relatively cheap natural gas has had a dramatic effect on the economics of both thermal and renewable generation resources. Larger companies are generally better positioned to withstand the panoply of risks they face, whether they be from weather, commodity cost volatility, regulatory factors or local economic cycles. A favorable economic environment and the continuation of historically low interest rates provided a tail wind for transactions during the past three years. Finally, the higher growth rates and lower levels of volatility in earnings of LDCs compared to regulated electric operations, together with the increased scarcity of pure play regulated gas companies, has resulted in an extraordinary level of interest in these companies. Looking forward, we expect consolidation to continue, most likely episodically and with levels of activity that vary dramatically among industry sectors. Among regulated companies, it is difficult to see how the level of activity over the past couple of years can continue. There are indications that increasing interest rates and higher levels of regulatory scrutiny may create at least modest headwinds for additional deals. We expect the strong demand for gas distribution companies to continue, but there are only a limited number of such companies, and an even smaller number that are interested in pursuing a transaction. Consequently, we see the level of activity among regulated companies in 2017 as likely to decrease from the levels of the past three years. Renewable assets continue to generate strong interest among strategic buyers and private equity funds, and consequently we expect that renewables M&A will remain active in 2017. Indications are that activity will continue in the generation sector at levels similar to previous years, particularly as regards gas-fired generation. There are several sale processes underway or being considered and the demand for good quality assets appears strong. In the oil and gas sector, M&A activity in 2017 will likely continue to be driven by the intense financial stress that many oil and gas companies are under. There were several distress-driven transactions during 2016; we may see more in 2017. Of course the other major uncertainty all companies are facing is the legislative and regulatory reform that will come about under the Trump Administration. Expectations are that the Trump Administration will make significant efforts to change regulations pertaining to the environment and related energy regulatory matters while also working towards wholesale tax reform. We have included discussion of the potential implications of reforms that might be pursued by the Trump Administration in many of the sections below (see Renewables, Environmental Regulation and FERC). We also have included a separate section discussing the possibility for Page 3 tax reform during 2017 and what that reform might look like based on President Trump’s campaign proposals and the House Republicans’ “A Better Way” white paper. The discussion below covers the following areas:  Regulated Utilities  Independent Power Producers and Generation Assets  Renewables  Master Limited Partnerships and YieldCos  Project Finance  Bankruptcy Developments in the Energy Sector  Environmental Regulation  FERC  LNG  CFTC  ERCOT  Distributed Generation  Energy Efficiency  Potential Tax Reform Under the Trump Administration  Mexican Power Markets Regulated Utilities Key trends among transactions involving regulated electric and gas companies include (i) the extraordinary valuations that sellers have achieved over the past several years, (ii) the prevalence of reverse break-up fees payable by acquirers in the event that regulatory approvals are not obtained, and (iii) the prevalence of non-US (primarily Canadian) buyers in the transactions announced over the past four years. The chart attached as Exhibit A shows several of the key metrics for transactions involving regulated electric and gas companies since 2013. Valuations can be assessed using a variety of metrics. One commonly cited metric is the premium of the acquisition price over the market price of the target company’s stock before the transaction is announced. This number is easy to calculate and understand. It tells a shareholder Page 4 how much more he or she can obtain for a share of stock as a result of the transaction. However, the premium to market is subject to wide variation due to a variety of factors, not the least of which is market expectations about whether a company is likely to enter into a transaction. Consequently, we would argue that other measures are more meaningful when comparing valuations among different transactions. Acquirers and financial advisers typically assess valuations by comparing the acquisition price to financial metrics of the target company such as historical and expected earnings and EBITDA.2 Another commonly used method is based on the expected discounted cash flow of the target company. Performing a so-called DCF analysis is a complicated process that requires a high degree of financial expertise as well as access to nonpublic information about a company’s business plan and internal financial projections. For purposes of this discussion, we will limit our analysis to three commonly used valuation measures that are relatively easy to calculate based on publicly available information: acquisition price as a multiple of (i) expected earnings for the next year, (ii) the previous year’s earnings and (iii) EBITDA for the previous year. We believe that these metrics provide better comparability of valuation levels among transactions than the premium to market price prior to announcement. The chart below details how these multiples have changed over the past twelve years. Average Valuation Multiples – Electric and Gas Utility Mergers and Acquisitions (2005 – 2017) Year(s) Forward P/E LTM P/E Transaction Value/EBITDA 2017 26.2 26.7 13.4 2016 22.1 25.5 11.7 2015 25.3 28.6 11.5 2014 19.6 19.0 9.1 2013 19.3 18.9 8.9 2005 – 2012 17.3 16.2 8.3 During the decade prior to 2013, average multiples were below any of the averages for any year since 2012. Multiples rose in 2013 and again in 2014. In 2015, they jumped significantly, and generally have remained in that range ever since. Another trend worth commenting on is the appearance of reverse break-up fees in transactions involving regulated companies. These provisions require the buyer to pay a fee to the seller in the event the transaction does not close for specified reasons, typically either a financing failure or a failure to obtain required regulatory approvals. Reverse break-up fees have been common for some time in transactions outside the utility industry. Initially, these provisions were used to 2 Earnings before interest, taxes, depreciation and amortization. Page 5 provide financial buyers with a way to get out of a transaction if financing was not available when it came time to close. The mechanism spread to transactions involving strategic buyers, where a buyer would be required to pay the fee if it did not obtain the necessary anti-trust clearance for the transaction. Since these fees are generally at least 3%, and often more than 5%, of the equity value of the transaction, a reverse break-up fee creates a strong incentive for a buyer to do whatever is necessary to close a transaction, including obtaining antitrust clearance and the other regulatory approvals. At first reverse break-up fees were seen in energy and utility transactions only in competitive bidding situations where a buyer intended to obtain financing for the transaction. Beginning with the Pepco/Exelon transaction in 2014, however, a reverse break-up fee was payable upon the failure to obtain the required regulatory approvals, and since that time this approach has become common in electric and gas utility acquisitions. In the Pepco transaction, the reverse break-up fee was structured as a mandatory purchase by Exelon of a block of preferred stock that was redeemable by Pepco at its original purchase price in the event regulatory approvals were obtained, and for no consideration if all regulatory approvals were not obtained. Since then 11 of the 13 major announced transactions (AGL/Southern Company and UIL/Iberdrola being the two exceptions) have included some form of reverse break-up fee. Fees have ranged in size from a low of 2.60% of equity value in the Pepco/Exelon deal to a high of 5.35% in Cleco/Macquarie. Exhibit A provides more detail regarding the size of these fees and how they compare to the primary break-up fee for the target company. The recently announced WGL Holdings/AltaGas transaction included an interesting nuance in the reverse break-up fees; there three fees were specified, a Parent Termination Fee of one $182 million, a Regulatory Termination Fee of $68 million and a Financing Termination Fee of $205 million. 2016 also marked the first time that a reverse break-up fee had to be paid in a transaction involving a regulated electric or gas utility. After a long and difficult regulatory process, the Hawaii Public Utilities Commission dismissed the merger application for the proposed transaction between NextEra and Hawaiian Electric Company. Following termination of the merger agreement, NextEra paid Hawaiian Electric Industries, Inc. a termination fee of $90 million. The events leading up to the termination are discussed in more detail below. Another trend worth noting is the prevalence of Canadian buyers in the transactions announced over the past four years. Of the 15 transactions announced since the beginning of 2013, seven have involved buyers from outside the United States. Of those seven, six were either exclusively or predominantly Canadian (predominately Canadian in the case of the Cleco transaction that involved Macquarie and a Canadian pension fund). There appear to be several reasons for this phenomenon. The Canadian companies have some tax advantages with respect to acquisitions that are not available to acquirers in the United States. Also, the Canadian capital markets appear to be quite supportive of these transactions, as evidenced by the ability of Canadian companies to finance the equity portion of these investments with convertible debt offerings where investors earn a substantial return on their investment prior to the closing of the transaction while making their investment on an installment basis. Some of these offerings are described in more detail below. Finally, for a Canadian company that wants to expand, the United States is an obvious choice given the geographic proximity and that there are more acquisition opportunities here than in Canada. Page 6 With respect to specific transactions, 2016 began with six pending deals involving regulated companies. Of these, five closed during the year (Pepco/Exelon, Cleco/Macquarie, AGL/Southern, TECO/Emera and Piedmont/Duke) and one was terminated (HEI/NextEra). Four new transactions were announced (Questar/Dominion, ITC Holdings/Fortis, Empire District/Algonquin and Westar/Great Plains), of which only the Westar transaction is still pending. There also was significant activity surrounding Oncor Electric Delivery Company LLC, with NextEra entering into a series of transactions pursuant to which it would acquire, among other things, Energy Future Holdings Corp. and all of the outstanding equity interests of Oncor. That transaction also is still pending, and is discussed in more detail below. So far in 2017, only one major transaction has been announced, the acquisition of WGL Holdings by AltaGas Ltd. Pepco/Exelon Exelon Corporation and Pepco Holdings announced their proposed combination in April of 2014. Approvals or clearances required for the transaction included Pepco stockholders, HartScott Rodino, FERC, and utility regulatory commissions in the District of Columbia, Delaware, Maryland, New Jersey and Virginia. By August 2015, the transaction seemed to be on course to close well before year-end, having obtained all approvals except the District of Columbia Public Service Commission. Unfortunately, on August 28, 2015 the DCPSC issued an order denying approval for the transaction. In its order the DCPSC expressed concerns that the proposed management structure would diminish Pepco’s role and ability to make decisions responding to the needs of DC ratepayers and policy directives, and that the proposed merger, taken as a whole, did not meet the District’s threshold for a net public benefit, rather than a simple no harm standard. The Commission acknowledged that there would be benefits associated with the merger, but also expressed concern over potential harms that could result from the transaction. On balance, the Commission concluded that the potential benefits did not outweigh the potential harms and consequently rejected the transaction. One Commissioner dissented on the grounds that the other Commissioners had not sufficiently explored the potential to mitigate deficiencies in the merger by imposing conditions on the parties and did not provide guidance regarding how the Commission’s concerns could be addressed. The companies launched an intensive effort to get things back on track, filing a request for rehearing on September 28th, and following that up in October with a settlement agreement with the Mayor of the District and other key constituencies that included significant enhancements to the proposed package of benefits to customers and others. The Mayor, the DC Council and numerous others came out in support of the transaction. Opponents of the transaction also waded in, causing the Commission to reopen the record in the proceeding so that it could consider additional evidence regarding the settlement agreement. The Maryland Attorney General also made an unsuccessful effort to have the Maryland PSC’s approval of the transaction vacated. On February 26, 2016, the DCPSC, by a 2 to 1 vote, rejected the proposed settlement, but also presented a series of conditions that, if accepted by the parties would result in automatic approval of the deal. An intense few weeks followed. After some of the parties said they would not agree Page 7 to the conditions, Exelon and Pepco offered additional benefits. On March 23, in a vote that surprised many observers, the Commission voted, again with one dissent, to approve the merger, subject to the conditions that it had offered in its February 26th order. The transaction closed later that day. Unfortunately, even the closing has not ended the dissension over the transaction. The District of Columbia and one of its consumer advocates have filed an appeal of the regulatory approval of the transaction challenging the regulators' rejection of certain settlement terms that the stakeholders had accepted. The matter is in the process of being briefed. Whether anything will come of it remains to be seen. Cleco/Macquarie/BCIMC The Cleco transaction was announced on October 20, 2014. Cleco, its public utility subsidiaries and the investor group making the acquisition filed for Louisiana Public Service Commission approval on February 10, 2015 and FERC approval on April 2, 2015. They proposed ringfencing commitments intended to insulate Cleco Power from its parent companies and affiliates, confirmed that Cleco Power President Darren Olagues was expected to become president and CEO of Cleco and committed that the company’s headquarters would remain in Pineville, Louisiana following completion of the transaction. The parties also indicated that Cleco would continue to operate as an independent company led by local management, and that no changes would be made to the company’s operations, staffing levels, compensation levels or employee and retiree benefits programs as a result of the transaction. The parties were optimistic that they could close the transaction during 2015. Although approval from FERC came fairly quickly and without significant conditions, the Louisiana PSC decision took much longer. The Louisiana PSC Staff did not file its testimony in the proceeding until the end of July, over 5 months after Cleco and the investor group filed the initial application. Moreover, the Staff recommended that the transaction not be approved, although they did offer up a litany of conditions that might mitigate their concerns. Many of these conditions were directed at mitigating financial risks to Cleco. Subsequent to the Staff’s testimony, Cleco and the investors proffered two rounds of enhanced commitments to customers and other constituencies, the most recent being in early January of 2016. The cumulative additional enhancements included a $125 million rate credit, a series of financial undertakings designed to preserve Cleco Power’s investment grade credit rating and protections for employees. Unfortunately, the additional concessions were not sufficient to win Louisiana PSC approval of the transaction. On February 17, 2016, the ALJ overseeing the review of the proposed sale recommended against the transaction. This decision was followed on February 24th by a rejection from the Commission itself. The parties sought a rehearing of the decision and simultaneously offered up additional commitments in connection with the merger. Finally, on March 28, 2016, the Louisiana PSC made an about face and approved the transaction. The transaction closed on April 13, 2016. Page 8 NextEra/Hawaiian Electric Unfortunately, despite a lengthy process during which both companies maintained steadfast commitment to the transaction, NextEra and Hawaii Electric Industries were not able to overcome objections to their proposed merger. The companies initially announced the $4.3 billion transaction on December 3, 2014. It required the approval of the Hawaii Public Utilities Commission, FERC and HEI’s shareholders. Initially, the companies expected to complete the deal by the end of 2015. FERC and shareholder approval were obtained without difficulty within a few months after the announcement. However, the HPUC proceeding became lengthy and controversial. The initial application with the HPUC was filed on January 29, 2015 and included commitments that Hawaiian Electric would not submit any applications seeking a general base rate increase and would forego recovery of the incremental operations and maintenance revenue adjustment under its decoupling rate mechanism for at least the first four years following closing. The companies asserted that these undertakings would result in approximately $60 million in cumulative savings for Hawaiian Electric’s customers. NextEra also committed to not seek to recover through Hawaiian Electric rates any acquisition premium, transaction or transition costs that might arise from the acquisition, and that there would be no involuntary reductions to Hawaiian Electric’s workforce as a result of the transaction for at least two years after closing. NextEra also proposed a series of ring-fencing provisions designed to ensure that Hawaiian Electric and its customers were not impacted by NextEra’s other activities and businesses. After the initial filing, the proceeding became embroiled in a debate over Hawaii’s energy policy over the next couple decades. The companies advocated that the transaction be approved on the basis that the combination would let them implement a shared vison of increasing renewable energy in Hawaii, modernize the islands’ electric grid, reduce Hawaii’s dependence on imported oil, integrate more rooftop solar energy and generally lower customer bills. Nevertheless, opposition persisted. The consumer advocate attempted to slow the proceedings down, but the effort was rejected by the PUC. Various political groups on the islands were reported to be considering ways to convert Maui Electric Co. and other HEI utility subsidiaries into government-owned public utilities. The Governor also came out against the combination, and various legislative initiatives were launched that would impose additional hurdles to completion of the merger. The companies pressed on despite the opposition, citing the potential for $1 billion in merger-related savings, boosted their proposed commitments to customers and emphasized that the company would continue to be locally managed following the merger. The companies also extended the termination date under the Merger Agreement to accommodate additional delay in the proceeding. Unfortunately, these efforts were to no avail, as on July 15, 2016 the Hawaii Public Utilities Commission dismissed the companies’ application for approval of the merger. The Commission’s decision concluded that, while NextEra was fit, willing and able to perform the services that would be required of the owner of the Hawaiian Electric Companies, the applicants had failed to demonstrate that the transaction was reasonable and in the public interest. In reaching its conclusion, the Commission focused on five fundamental areas of concern: benefits to ratepayers, risks to ratepayers, applicants’ clean energy commitments, the proposed change of Page 9 control’s effect on local governments and the proposed change of control’s effect on competition in local energy markets. The Commission then went on to provide a detailed list of concerns and uncertainties associated with each of these categories. Although, the dismissal was without prejudice, the tone of the order was quite negative. After reviewing the order, on July 18, 2016, the companies announced that they had terminated their merger agreement. Upon termination, NextEra also paid to Hawaiian Electric Company a break-up fee of $90 million plus reimbursed expenses of up to $5 million. This appears to be the first instance in the electric and gas utility industries of a reverse breakup fee being paid following termination of an acquisition agreement upon failure to obtain regulatory approvals. AGL Resources Inc./Southern Company In late August of 2015, Southern Company announced that it would acquire AGL Resources in a $12 billion transaction. AGL shareholders received $66 in cash per share for their stock, representing a premium of 36.3% to the volume-weighted average stock price for the 20 trading days prior the announcement and a multiple of 21.8 times forward earnings. The merger created the second-largest U.S. utility company, with 11 regulated electric and natural gas distribution companies, operating nearly 200,000 miles of electric transmission and distribution lines and over 80,000 miles of gas pipelines, as well as a generating capacity of about 46,000 MW. The transaction represented a step in a new strategic direction for Southern and was well received by analysts and stockholders. Southern funded the deal through debt and equity, with roughly $3 billion in equity issuances to be spaced out through 2019. After closing, AGL retained much of its management team, board of directors and corporate headquarters in Atlanta. Existing customers will continue to be served by their respective utilities. In addition to the usual Hart-Scott-Rodino clearance and FCC approval, the transaction required approval from regulators in seven states - Georgia, Illinois, Maryland, New Jersey, California, Tennessee and Virginia. All of the approvals were obtained without difficulty, with New Jersey being the last to issue its order on June 29, 2016. The transaction closed on July 1, 2016. TECO Energy, Inc./Emera Incorporated Less than two weeks after the AGL/Southern transaction was announced, TECO Energy disclosed on September 4, 2015 that it would be acquired by Emera Inc. in an all-cash deal worth $10.4 billion, including assumption of about $3.9 billion of debt. The announcement followed a robust bidding process that had been previously disclosed by TECO. TECO shareholders received $27.55 per share in cash, a 48% premium to the unaffected closing share price of July 15, which was the day before TECO disclosed that it was exploring strategic alternatives for the company. The price also represented a multiple of 24.7 times forward earnings. The combined company has more than $20 billion in assets and more than 2.4 million electric and gas customers. For Emera, the transaction culminated a long search for an expansion opportunity; management expects the transaction to give the company additional geographic, regulatory and business diversification. The deal expanded Emera’s geographic platform into Florida and New Mexico, Page 10 adding two new regions beyond its existing U.S. base in the Northeast. Emera is headquartered in Nova Scotia, where it owns local electric utility Nova Scotia Power Inc. It also owns more than 1,400 MW of generating capacity in New England. Now that the deal has been completed, 56% of Emera’s asset base is in Florida, 23% in Canada, 10% in New England, 6% in New Mexico and 3% in the Caribbean. Shortly after announcement, Emera entered into a financing arrangement for the equity portion of the acquisition, issuing C$1.9 billion of 4.00% convertible unsecured subordinated debentures. The debentures were sold on an installment basis at a price of C$1000 per debenture, of which C$333 was paid on closing with the remaining C$667 payable on a date to be fixed following satisfaction of all conditions precedent to closing. Prior to the final installment date, the debentures were represented by installment receipts and were listed and posted for trading on the Toronto Stock exchange. The financing fully addressed Emera’s common equity financing needs for the acquisition. Closing was subject to TECO shareholder approval, approval by the New Mexico Public Regulation Commission and FERC, and Hart-Scott-Rodino and CFIUS (Committee On Foreign Investment in the United States) clearance. Shareholder approval was obtained on December 3, 2015, FERC granted its approval on January 21, 2016, the Hart-Scott-Rodino waiting period expired on February 8, 2016 and CFIUS clearance was granted on March 23rd. The companies also reached a settlement in the New Mexico proceeding with the New Mexico order being issued on June 22, 2016. Closing occurred on July 1, 2016. Piedmont Natural Gas/Duke Energy The last major transaction of 2015 involving regulated utility companies came on October 26 when Duke announced that it would acquire Piedmont Natural Gas Company for $4.9 billion in cash plus assumption of approximately $1.8 billion in Piedmont existing debt. Piedmont shareholders received $60 per share for their equity, an extraordinary 40% premium to the closing price on the trading day prior to announcement and an industry high water mark of 30.9 times forward earnings. Based on the proxy material filed by Piedmont with the Securities and Exchange Commission, the agreement was the result of a process conducted by Piedmont that included at least one other active bidder. Conditions to the transaction included approval by the North Carolina Utilities Commission and the Tennessee Regulatory Authority, as well as Hart-Scott-Rodino clearance and Piedmont shareholder approval. The companies also provided information regarding the acquisition to the Public Service Commission of South Carolina. Regulatory approvals were obtained without significant difficulty and the transaction closed on October 3, 2016. Questar/Dominion The first major merger announcement of 2016 was on February 1, 2016, when Dominion Resources, Inc. unveiled its acquisition of Questar Corporation for approximately $6 billion, including assumption of $1.6 billion of debt. Two important drivers of this transaction were that it gave Questar an opportunity to contribute its pipeline assets to an MLP (Dominion Midstream) even though it did not have the scale to establish its own MLP, and potential geographic Page 11 expansion for Dominion. The 1-day premium to market was 23.2% and the multiple to forward earnings was 19.1x, relatively moderate numbers by 2015 standards, but still a substantial premium. The transaction required Hart Scott Rodino clearance and state approvals in Utah and Wyoming, all of which were obtained without difficulty. Dominion financed the transaction with a combination of debt and equity. It closed on September 16, 2016. ITC Holdings/Fortis Inc. Two additional transactions were announced a few days later on February 9, 2016. The first of these was the announcement by Fortis Inc. and ITC Holdings Corp. of an agreement pursuant to which Fortis would acquire ITC for approximately $7 billion. ITC received $22.57 in cash and 0.7520 Fortis shares per ITC share. Fortis also assumed approximately $4.4 billion of consolidated ITC indebtedness. The financing of the cash portion was achieved through the issuance of approximately $2 billion of Fortis debt similar to the Emera financing described above, and the sale of a 19.9% stake in ITC to GIC Pte, Ltd. for $1.2 billion. Upon completion of the acquisition, ITC became a subsidiary of Fortis with approximately 27% of the common shares of Fortis being held by former ITC shareholders. Fortis listed its common shares on the New York Stock Exchange in connection with the acquisition and continues to list its shares on the Toronto Stock Exchange. The transaction was subject to HSR and CFIUS clearance as well as approval from FERC and state regulators in Illinois, Kansas, Missouri, Oklahoma and Wisconsin. The companies did not seek state approvals in Iowa, Michigan or Minnesota. Despite the larger number of states with jurisdiction over the transaction, the process went relatively smoothly and closing took place on October 14, 2016. The Empire District Electric Company/Algonquin Power and Utilities Corp. The second transaction announced on February 9th was the acquisition by Liberty Utilities (Central) Co., a subsidiary of Algonquin Power & Utilities Corp., of The Empire District Electric Company for $34 per share in cash, representing an aggregate purchase price of approximately $2.4 billion, including the assumption of approximately $0.9 billion of debt. Algonquin obtained a $1.6 billion bridge facility to finance the transaction. Permanent financing was obtained by placements of common equity, preferred equity, convertible debentures and long term debt, along with the assumption of existing Empire indebtedness. Algonquin commenced the financing process in February with a C$1 billion convertible debt offering similar to the Emera offering described above. The transaction was subject to approval of Empire shareholders, state regulatory commissions in Arkansas, Kansas, Missouri and Oklahoma, the FCC, CFIUS and FERC, and HSR clearance, all of which were obtained without undue difficulty. The transaction closed on January 1, 2017. The management team of Empire District will continue to lead Liberty Utilities’ Central US Region and Algonquin expects to retain all Empire District employees. Consequently, no changes to management or employee staffing at Empire are expected as a result of the transaction. Page 12 Westar/Great Plains The next major merger announcement of 2016 came on May 31 when Great Plains Energy Inc. announced an agreement to acquire Westar Energy, Inc. in a $12.2 billion transaction. The agreement provides that Westar shareholders are to receive $60.00 per share of total consideration for each share, comprised of $51.00 per share in cash and $9.00 per share in Great Plains common stock. The stock portion of the consideration is subject to a 7.5% collar based upon the Great Plains common stock price at the time of closing, with the exchange ratio for the ranging between 0.2709 to 0.3148 shares of Great Plains common stock for each Westar share of common stock. This represents a consideration mix of 85% cash and 15% stock. Great Plains will also assume $3.3 billion of Westar’s net debt. The transaction is subject to Hart Scott Rodino clearance and approval from the FERC, NRC, FCC and Kansas Corporation Commission. When they announced the transaction, the companies also indicated that the Missouri Public Service Commission did not have jurisdiction over the deal, but the question of Missouri jurisdiction has turned out to be controversial. On June 5th, the Missouri PSC opened an investigation into the potential impact on Missouri ratepayers of the proposed acquisition, as had been requested by the Commission’s staff. In July, the PSC staff issued a report in which it expressed the opinion that the commission does have jurisdiction over the transaction because of conditions that Great Plains had agreed to when it set up a holding company in 2001. The staff also raised several substantive concerns about the transaction’s potential effects on Missouri ratepayers. On August 3, 2016, the Missouri Public Service Commission required that the proceeding be closed on the ground that it was only an “investigatory docket, not a case, contested or otherwise.” Great Plains did file for a waiver of certain restrictions on affiliate transactions, which it requested in order to implement post-closing activities of the two companies, and in that context the staff continued to work with Great Plains to get its concerns addressed. On October 12th Great Plains and the PSC staff filed a settlement that among other things addresses the concerns expressed by the staff in its earlier report. The issues addressed in the settlement were primarily ring-fencing provisions to protect Missouri ratepayers from any adverse effects of the transaction and agreements with respect to recovery of certain costs associated with the transaction. The question of Missouri jurisdiction was raised again in early November when a consumer advocacy group filed a complaint at the Missouri PSC arguing that the PSC does have jurisdiction over the merger under Great Plains’ 2001 holding company order. On January 4, 2017, the PSC denied a motion by Great Plains to dismiss the complaint, which remains pending. Meanwhile, on December 16, 2016, the staff of the Kansas Corporation Commission recommended that the proposed merger be rejected for not being in the public interest. The Missouri Commission asked its staff to examine the recommendation and report back to it, which the staff did on January 18, 2017. It is too soon to say how serious a hurdle the Kansas staff’s recommendation is for the merger. Hearings were held in early February, but no ruling has been made as of the date of this memorandum. As chronicled in our memos over the years, many utility mergers have faced much more daunting opposition and yet ultimately been approved. That may well be the case with this one. Thing still seem to be on track for a decision from Kansas by April 24, 2017. Page 13 EFH/NextEra/ONCOR After Energy Future Holdings failed to get approval to transfer its 80% ownership interest in Oncor Electric Delivery Company (“ONCOR”) to Hunt Consolidated as part of a broader plan to emerge from bankruptcy, EFH negotiated a deal in the fall of 2016 to transfer its 80% interest in ONCOR to NextEra Energy. On November 1, 2016, NextEra and ONCOR filed a joint application with the Public Utility Commission of Texas (PUCT) requesting approval of two mergers to accomplish the transaction. First, NextEra would acquire the 80% stake in ONCOR held by EFIH, an indirect subsidiary of EFH and second, a NextEra affiliate would merge with Texas Transmission Holdings Corporation which owns the remaining 20% indirect interest in ONCOR. In a press release announcing the transactions, the parties described the transactions in the aggregate as a “straightforward, traditional merger by a utility holding company” to distinguish it from the novel REIT structure that was to be employed in the Hunt transaction. The parties further pledged to keep ONCOR ring-fenced similar to its existing structure (and as did Hunt under its proposed transaction). That said, as described below, the EFH saga has continued into 2017 for reasons beyond the success or failure of a merger transaction for ONCOR. WGL Holdings, Inc./AltaGas Ltd. In the first major announcement of the new year, on January 25, 2017, WGL Holdings and AltaGas Ltd. unveiled a $6.4 billion transaction in which AltaGas will acquire WGL holdings for $88.25 per share in cash. The price represented a 27.9% premium to WGL’s share price on November 28, 2016, the last trading day prior to a Bloomberg article regarding potential takeover interest in WGL and approximately 26.2 times WGL’s expected 2017 earnings. WGL will maintain its utility headquarters in Washington, D.C. and WGL’s existing management will continue to manage WGL’s regulated utility business, while also assisting in the management of AltaGas’ US regulated utility business. AltaGas also intends to relocate the headquarters of its US power business to WGL’s service region. Consummation of the transaction is subject to certain closing conditions, including WGL shareholder approval, and approvals from the Public Service Commission of the District of Columbia, the Maryland Public Service Commission and the Virginia State Corporation Commission. WGL and AltaGas plan to submit the transaction for review by the Committee on Foreign Investment in the United States. The agreement will also be subject to Federal Regulatory Energy Commission approval, and expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Independent Power Producers and Generation Assets IPP Activity The unregulated side of the electric industry saw a dramatic uptick in M&A activity, with approximately $33.5 billion in electric generation transactions, up from $8.5 billion in 2015, and $12.3 billion in 2014. Much of this volume related to the NextEra/EFH transaction, but even without that $18 plus billion transaction, volumes were up in 2016. The value of transactions involving renewable generation assets decreased from $8.5 billion to $6.6 billion. Much of the activity focused on large portfolio divestitures, such as the recent AEP divestiture to Blackstone and ArcLight and the Engie divestiture to Dynegy. There was a marked increase in activity by Page 14 private equity and other financial investors from 2015. This trend appears to be continuing in 2017 with the announcement of LS Power’s planned purchase of generation from FirstEnergy. Engie/Dynegy-Energy Capital Partners On February 25, 2016, Dynegy and Energy Capital Partners formed a joint venture, Atlas Power, to buy Engie’s 8.7 GW fossil fuel-fired generation portfolio for approximately $3.3 billion or $378/kW. In June, Dynegy announced that it was buying Energy Capital Partners out of the JV for approximately $750 million and assuming additional debt to take 100% ownership in the Engie assets. Dynegy had expected to close the transaction by the end of 2016, however, FERC raised several concerns about the transaction’s potential impact on the capacity markets in ComEd in PJM and Southeast New England in its order dated December 22, 2016. On December 27, 2016, Dynegy filed with FERC a proposed mitigation plan that includes divesting generation and imposing capacity bidding limits. FERC approved the plan in early February and the transaction proceeded to closing on February 7, 2017. TransCanada/LS Power In November, LS Power signed an agreement with TransCanada to purchase a portfolio of generation in the Northeastern U.S. for approximately $2.2 billion. The transaction included the sale of the Ravenswood station in Queens, the Ironwood station in PJM, the Ocean State station in Rhode Island, and Kibby Wind in Maine. At the same time, TransCanada also announced the sale of 13 hydropower facilities in New England to ArcLight for approximately $1.1 billion. Both transactions are expected to close in the first half of 2017. NRG/LS Power In May 2016, LS Power announced that it would acquire the 878 MW Aurora gas-fired power plant for $365 million and the 297 MW Rockford I gas-fired plant and the 153 MW Rockford II gas-fired plant from NRG for an undisclosed sum. The plants are located in Illinois and PJM. AEP/Blackstone-ArcLight In September 2016, Blackstone and ArcLight announced their acquisition of 5,000 MW of merchant generation in Ohio and Indiana for approximately $2.2 billion. AEP auctioned the assets after an unsuccessful attempt to move the assets back into ratebase. The transaction closed in late January 2017, after receiving required pre-approvals from the DOJ, the FERC and the Indiana Utility Regulatory Commission, with a new joint venture between Blackstone and ArcLight — Lightstone Generation, LLC — taking ownership of the generation fleet, which is located in PJM. Calpine/Southern Power In October 2016, Southern Power, the unregulated generation subsidiary of Southern Company, purchased the Mankato Energy Center in Minneapolis from Calpine for approximately $396 million. The 720 MW Mankato Energy Center (which includes a pending 345 MW expansion) is committed to Northern States Power. Page 15 Entergy Nuclear/Exelon In August 2016, Exelon announced its purchase of Entergy’s Fitzpatrick nuclear power station in upstate New York for $110 million. Upon closing, the decommissioning trust fund and related liability would also be assumed by Exelon. The transaction saves Fitzpatrick from the January 2017 shutdown Entergy announced last year. Since that time, the New York State Public Service Commission (“NYPSC”) has approved a Zero Emission Credit (“ZEC”), which could give up to $8 billion over twelve years to nuclear generation in NY. Several parties have contested the NYPSC’s ZEC order. The transaction requires numerous regulatory approvals, including that of FERC, the NRC, the NYPSC and the DOJ. It is expected to close in the second quarter of 2017. Talen/Riverstone In an interesting turn of events, Riverstone announced its intention to take Talen private in June 2016 for approximately $1.8 billion, or $14/share which was a 56% premium to its share price before public reports of the potential transaction. In 2015, Riverstone formed Talen with the PPL unregulated generation subsidiary. The going private transaction closed on December 6, 2016. In exchange for certain regulatory approvals when Talen was formed, Talen had to divest the Holtwood and Lake Wallenpaupack hydro projects to Brookfield Asset Management for $860 million and the Ironwood project for $654 million to TransCanada, which were announced in 2015 and closed in early 2016. Calypso Energy Holdings/FP&L In June 2016, Florida Power & Light announced its plans to purchase the coal-fired Indiantown Cogeneration facility in southern Florida from Calypso Energy Holdings for approximately $450 million. Indiantown has a long-term power sales agreement with FP&L. FP&L stated that it intends to decrease the output and eventually retire Indiantown by 2019, when a new gas pipeline and FP&L’s Okeechobee County gas-fired generating facility are expected to be in service. Entegra Power/SRP On September 20, 2016, Salt River Project announced the purchase of a power block at the Gila River generating station from Entegra Power in Arizona for approximately $100 million. Entegra sold another power block to Tucson Electric in 2014. Entegra Power had previously filed a prepackaged bankruptcy plan and emerged from Chapter 11 in 2014. The sale to SRP is expected to close May 2017. Weyerhaeuser/International Paper On December 2, 2016, International Paper completed the acquisition of Weyerhaeuser’s pulp business, including five QF facilities associated with mill sites in the U.S. and one power plant in Alberta, Canada, for approximately $2.2 billion. The combined business will be called Global Cellulose Fibers. Page 16 NextEra/EFH NextEra’s bid for Oncor, the regulated subsidiary of Energy Future Holdings Corp. (“EFH”), continued into 2016. The Oncor transaction is described in more detail above. NextEra signed a merger agreement with Energy Future Intermediate Holding Company and EFH in July 2016, which was met with several obstacles in court and at the PUCT. NextEra and EFH filed a joint application to approve the merger with the PUCT in October 2016. The PUCT set a procedural schedule with hearings in late February 2017. The merger and reorganization of EFH in bankruptcy is pending. Retail Electric Commodity Businesses There also were several transactions involving retail commodity businesses announced during the year. Calpine purchased Noble Americas retail C&I business for $800 million, which closed in December. Consolidated Edison Solutions sold its retail C&I and residential business to Exelon in September 2016. In November, Genie Energy acquired Retail Energy Holdings for $10 million. In January CenterPoint Energy Services purchased Continuum Energy’s retail energy services business and natural gas wholesale assets. Renewables Renewables M&A Activity M&A activity in the renewables space tapered off in 2016, with announced deals totaling $6.6 billion as compared to $8.5 billion in 2015 and $7.5 billion in 2014. Tesla’s $2.6 billion acquisition of Solar City was by far the largest transaction of the year, followed by two large transactions in the hydro space in New England: Public Sector Pension Investment Board’s acquisition from Engie of a portfolio of hydropower assets for $1.2 billion and ArcLight’s acquisition from TransCanada of a portfolio of hydropower assets for $1.1 billion. Southern Power Company also maintained its focus on renewables, with acquisitions totaling $596M in the wind space. Notes on selected transactions follow: Tesla/SolarCity On August 1, 2016, Tesla Motors, Inc. (Tesla) announced the acquisition of SolarCity Corp. (SolarCity) in an all-stock transaction valued at approximately $2.6 billion. The transaction combines Tesla, the electric vehicle manufacturer that has expanded into the energy storage business, with SolarCity, the market leader in the residential solar space. Both companies were backed by Elon Musk, who is the CEO of Tesla and its largest shareholder, owning more than 20% of its outstanding stock. Mr. Musk is also the Chairman of SolarCity and its largest shareholder, also owning more than 20% of its outstanding stock, with his first cousin serving as CEO. Not surprisingly, given Mr. Musk’s position, and the fact that SolarCity was operating at a loss and in need of capital, the transaction raised some concerns amongst corporate governance watchdogs. SolarCity was given a 45-day go-shop period and Musk recused himself from all valuation discussions leading up to the transaction and agreed to vote all of his shares proportionately with the votes cast by the public shareholders. The shareholders of both Page 17 companies approved the transaction on November 17, 2016, and the transaction proceeded to closing on November 21, 2016. PSP Investment/Engie On February 25, 2016, Canada’s Public Sector Pension Investment Board (PSP Investment) announced the acquisition of a portfolio of hydropower assets from Engie SA (Engie). The portfolio consists of approximately 1.4 GW of hydropower assets on the Connecticut River in Massachusetts and the Housatonic River in Connecticut, including the 1,168 MW Northfield Mountain pumped-storage facility as well as 12 other hydropower plants. This represented a major expansion for PSP Investments hydropower holdings, which until recently had consisted of approximately 140 MW of hydropower facilities in Canada and 31.5 MW of hydropower facilities in Pennsylvania. The transaction was subject to FERC approval, which was obtained on May 23, 2016, after which the transaction proceeded to closing on June 1, 2016. ArcLight/TransCanada On November 1, 2016, ArcLight Capital Partners (ArcLight) announced the acquisition from TransCanada of a 572 MW portfolio of hydropower assets for $1.1 billion. The assets consist of two systems comprising 13 dams and 43 hydroelectric units, with one system on the Connecticut River in New Hampshire and Vermont totaling approximately 490 MW and the other on the Deerfield River in Massachusetts and Vermont totaling approximately 82 MW. Upon closing, the existing power purchase agreement with TransCanada will be terminated and the portfolio will thereafter operate on a merchant basis. The transaction was subject to FERC approval, which was obtained on January 10, 2017. The transaction is still pending. Southern Southern Power Company followed up on a very busy 2015 with an equally busy 2016. On March 11, 2016, Southern announced the acquisition of the 40 MW Passadumkaeag wind facility from Quantum Energy Partners for $127 million. The transaction came about following the collapse of an earlier deal with SunEdison. FERC approved the transaction on April 20, 2016 and the deal proceeded to closing on June 30, 2016. On June 14, 2016, Southern announced the acquisition of a 90% stake in the 257 MW Wake wind energy facility from Invenergy for $469 million. Invenergy is retaining the remaining 10% stake in the project and will act as the operator. The transaction closed on October 26, 2016. In addition to these transactions, Southern made several other acquisitions during 2016 for which valuation data was not available, including the acquisition of six different solar projects and four wind projects. Regulatory Developments At the beginning of 2016, the big news on the regulatory front was the bi-partisan deal in Congress to extend the production and investment tax credits that are applicable to wind, solar and other renewable power projects. Congress retroactively reinstated and extended for 5 years the production tax credit (PTC) for wind facilities as well as the ability to elect the investment tax credit (ITC) in lieu of the PTC (in each case, subject to a phase out). In addition, the expiration date for the ITC for solar was extended by 5 years, subject to a phase out and with Page 18 changes in the methodology for qualifying. The legislation also extended “bonus depreciation” through 2019. Going into 2017 the most significant regulatory issue affecting renewables development is uncertainty. President Trump and Republicans in Congress have promised wholesale tax reform, and whether or how that might impact renewables development is not at all clear. Given the recent bi-partisan deal on the credits, it is possible that the credits will be left alone even in the context of larger tax reform (although this is certainly not assured). One exception to this might be the permanent 10% investment tax credit for utility solar (which is the rate that the ITC would default to after the phase out agreed to in 2015). This was left alone in the bi-partisan deal at the end of 2015, but in the context of wholesale tax reform it might be on the table. Another possible area that could be affected by these tax reform efforts could be the guidance issued by the Treasury Department on how to qualify for the production tax credit (applicable to wind). Recent guidance issued by the Treasury Department provided for a four year safe harbor to finish a project once the developer commenced construction, a significant loosening of the previous requirements, and in the context of wholesale tax reform it is possible this might also be revisited. Renewables Development Activity Wind. 2016 showed a significant drop off in completed wind projects as compared to 2015, with 1,725 MW of capacity installed in the first three quarters compared to 3,597 MW in the first three quarters of 2015. With the shift to a commencement of construction test for meeting the deadline to qualify for the production tax credit (as opposed to having to complete the project by the deadline) it can be expected that the fourth quarter may not show the same type of surge in the completion of projects that we have seen in the past, and even with a strong fourth quarter the totals for 2016 will be significantly below 2015 totals. 2017 may show more promise, however, as the American Wind Energy Association is reporting over 13,500 MW under construction, an increase from the 9,400 MW figure reported at the end of 2015. Also, corporate purchasers have signed power purchase agreements for 3,193 MW through the first three quarters of the year, a 39% year over year increase. Solar. Solar power installations showed very strong development activity in 2016, led by significant installations of utility scale solar. In the third quarter alone a record 4,143 MW of solar was installed, more than was installed in the first three quarters of 2015 combined, and GTM Research and the Solar Energy Industries Association are projecting an even stronger fourth quarter. Expectations are that total installations for 2016 will exceed 14 GW, an 88% increase over 2015. While the long-term extension of the ITC appears to have helped boost development activity in the utility scale solar segment, the residential solar market appears to have slowed down somewhat with lessening demand in some key states and regulatory hurdles in others around net metering. Page 19 Master Limited Partnerships (MLPs) and YieldCos MLP Capital Markets in 2016 During 2016, MLP market performance improved as overall stock market performance was robust and oil prices began to rebound and stabilize later in the year. For the first time since 2011, the Alerian MLP Index outperformed the S&P 500. The Alerian MLP Index increased 9.1%, with a total return of 18.3% (compared to a decline of 36.9% and a total return of (32.6)% in 2015). Among MLP equity securities, publicly traded general partners of MLPs and midstream MLPs provided the greatest total return. Upstream MLPs were the worst performers, as weak commodity prices led some to bankruptcy, and marine transportation and offshore drilling MLPs fared relatively poorly as low commodity prices continued to take their toll on those sectors. Despite overall stock price improvements, the MLP capital markets remained relatively slow during 2016, with the IPO market virtually non-existent. In 2016, there was one MLP IPO (Noble Midstream Partners) raising gross proceeds of $300 million. By comparison, there were nine MLP IPOs for $4.9 billion of gross proceeds in 2015 (all in the first half of the year) and 20 transactions for $7.7 billion of gross proceeds in 2014. During 2016, equity follow-on activity declined relative to 2015, but improved relative to the second half of 2015. In 2016, there were 32 follow on transactions for $6.6 billion of gross proceeds compared to 36 transactions for $9.1 billion of gross proceeds in 2015 (of which 28 transactions for $7.3 billion of gross proceeds occurred in the first half of 2015). Bought deals and confidentially marketed offerings (CMPOs) remained popular in light of market volatility. Bought deals provide greater certainty to the issuer as the lowest possible price at which the units will be sold is guaranteed by the underwriter. CMPOs provide the issuer with the ability to put together a complete book of investors at an acceptable price before publicly announcing the offering, while selling freely tradeable units to the investors. Private placements of equity also continued to be relatively popular. In 2016, there were 12 private placements/block trades to third parties or affiliates for $4.9 billion. PIPEs provide an opportunity to confidentially complete an offering, although the investors typically demand a greater discount than if they buy units in a public offering because the units are not freely tradeable until registered, although there is no underwriting discount in PIPEs. In addition, the tighter markets bred some creativity in capital raising. MLPs issued new classes of equity in an attempt to provide a product that is more attractive to certain private equity and affiliate investors, such as public offerings and targeted private placements of preferred securities (18 transactions), including convertible preferred units. The convertible preferred units provide the holders with an annual PIK and/or cash dividend at an attractive yield and an option to convert into common units after 18-24 months. The issuer also has the option to force conversion of the units if the market price of the common units rebounds to a certain level. In addition, MLPs continued to use their at-the-market (ATM) programs to feed their ongoing capital needs. ATM programs allow MLPs to issue targeted amounts of common units in broker transactions from time to time. Page 20 The debt capital markets, which were largely closed to MLPs in the second half of 2015, loosened in 2016. MLPs engaged in 25 bond offerings for $17.9 billion of gross proceeds in 2016, compared to 29 deals in 2015 for gross proceeds of $30.1 billion (23 of which, accounting for $24.5 billion of gross proceeds, occurred in the first half of 2015). In 2016, at least 9 MLPs cut distributions to unitholders (not all MLPs have yet announced their distributions in respect of the fourth quarter, which are paid in the first quarter of 2017). These cuts represent a continuation of 2015, the worst year in history for MLP distribution cuts, with 18 MLPs reducing their quarterly distributions to unitholders. The severe decline in oil prices and general decline in the capitals markets resulted in all upstream MLPs and most shipping, coal and oilfield services MLPs reducing or suspending their quarterly distribution between 2014 and 2016. In January 2017, the Department of the Treasury and the Internal Revenue Service issued longawaited final regulations on the scope of qualifying income under the Internal Revenue Code for MLPs engaged in activities with respect to minerals or natural resources. The final regulations include significant changes to the proposed regulations that were issued on May 2015. Importantly, the final regulations abandon the rule in the proposed regulations that the regulations constitute an “exclusive list” of all activities that can qualify. This will provide much greater flexibility to MLPs in evaluating the qualifying nature of activities not specifically listed in the regulations. The capital markets may slowly be starting to reopen for MLPs. In January 2017, there were three follow-on equity offerings for total gross proceeds of $300 million, and two public bond offerings for $2.0 billion of gross proceeds. In addition, in February 2017, Kimbell Royalty Partners, a mineral and royalty interest MLP, closed the first MLP IPO of 2017. We nevertheless expect there will be few MLP IPOs in 2017. MLP M&A in 2016 In 2016, M&A activity remained healthy. Transaction volume fell modestly (from 93 in 2015 to 72 in 2016). Most of the transactions were in the midstream industry.. However, disclosed deal values fell more significantly (from $95.6 billion in 2015 to $54.0 billion in 2016). MLP consolidation continued in the midstream sectors. MLP take privates and general partner sales also continued as sponsors came under financial or market pressure. The largest MLP M&A transaction announced in 2016 was Sunoco Logistics Partners $21.3 billion acquisition of Energy Transfer Partners (both MLPs were already in the Energy Transfer Equity family), which is still pending, followed by Plains All American Pipeline’s $7.2 billion simplification in which Plains bought back its incentive distribution rights and 2% general partner interest for newly issued limited partner units. Other notable transactions included Energy Transfer Partners’ acquisition of the general partner and a 65% limited partner interest in PennTex Midstream Partners, American Midstream Partners acquisition of JP Energy Partners, TransCanada’s acquisition of Columbia Pipeline Partners, SemGroup’s acquisition of the public’s stake in Rose Rock Midstream and Transocean Ltd.’s acquisition of the public’s stake in Transocean Partners. Page 21 Many midstream MLPs continued to grow their distributions through traditional drop-downs (i.e., an MLP’s accretive acquisition of assets from its sponsor) and acquisitions of targeted assets from other MLPs and private companies. However, as MLPs played it safe and steady in the volatile market, dropdowns did not have the historically high values seen in 2013, and MLPs with a drop down story took extra steps to highlight their sponsors’ inventories and support. MLPs also used more creative sources of financing dropdowns, including issuing preferred equity as acquisition consideration. MLP M&A is off to a strong start for 2017. Through January, 10 transaction have been announced for a disclosed value of approximately $17.2 billion. These transactions have included consolidation (Enbridge Energy’s pending acquisition of the outstanding publicly held interest in Midcoast Energy Partners), simplification (Williams Partners financial repositioning to eliminate the incentive distribution rights held by its general partner), combination (DCP Midstream Partners acquiring the assets and debt of DCP Midstream, LLC) and drop downs (Tallgrass Energy Partners acquiring Tallgrass Terminals). We expect to see continued buybacks and consolidation in 2017 as well as more simplification transactions to reduce or eliminate the capital cost burden of their incentive distribution rights. YieldCo Capital Markets in 2016 Unlike the previous three years, there were no YieldCo IPOs in 2016. However, the previously closed YieldCo debt and equity capital markets did open a bit, particularly in the third quarter, allowing for four equity offerings and one senior notes offering which provided an aggregate of $1.4 billion in new capital. YieldCo share prices were highly volatile throughout much of 2016, even though share prices remained relatively flat year-over-year. A number of factors influenced this volatility, the most significant of which were the bankruptcy of SunEdison (the world’s largest renewable energy developer) and its related effects on SunEdison’s two YieldCos, TerraForm Power and TerraForm Global, the election of a pro-coal President for whom climate change appears not to be a priority, and significant near-term market dislocation due to overseas competition. In early 2017, one YieldCo senior notes offiering has already closed, generating $350 million in new capital. Regardless, current indications are that the YieldCo debt and equity markets will remain tight through at least the first half of 2017. YieldCo M&A in 2016 M&A among YieldCos was relatively active in 2016, with a total of 12 acquisitions. These acquisitions, however, were completed by only three YieldCos, 8point3 Energy Partners, Pattern Energy Group and NextEra Energy Partners. In addition, all of the assets acquired by these three YieldCos were developed by their respective sponsors. Most notably, 8point3 Energy Partners completed six acquisitions in 2016, more than doubling its IPO portfolio of 432MW. Pattern Energy Group and NextEra Energy Partners each completed three acquisitions, adding to their already sizable portfolios. YieldCo M&A levels in 2017 will be dependent on a number of factors, notably access to additional capital, primarily through the equity capital markets. With an improved commodity price environment, greenshoots in the energy capital markets and a strong January for M&A, we are cautiously optimistic that 2017 will mark a turnaround in Page 22 activity for the MLP sector, including the capital markets with increased follow-on equity and high yield activity. However, we expect MLP IPO activity to remain limited in 2017. Project Finance As expected, the overall volume of transactions consummated in the US project finance market decreased markedly in 2016. The jumbo LNG financings that led to the impressive amount of new capital raised in recent years were noticeably absent in 2016, and activity in the conventional power sector was more moderate. Low commodity prices and a declining role for yieldcos also contributed to the lower volume. That said, the four main markets for the financing of energy projects -- commercial banks, term loan B, project bonds and tax equity -- remained relatively healthy throughout the year and, despite some uncertainty, still offer significant liquidity for well-structured projects as of early 2017. The commercial bank market continued to account for the majority of project finance activity in the United States. Large amounts of bank capital remained available throughout the year, with traditional European and Japanese project finance lenders keeping their position at the top of the league tables and a number of new entrants, primarily from South Korea, adding even more depth to the market. The structure of choice offering the most liquidity in the bank market is still the five- to seven-year mini-perm, but for contracted assets with long-term offtake contracts, longer tenors can also be available. Notable transactions consummated in the bank market in 2016 include the $2.5 billion financing for the Dakota Access and Energy Transfer Crude Oil Pipeline projects, being developed by Energy Transfer Partners, L.P., Sunoco Logistics Partners LP and Philipps 66. Also of interest, and an exception to the slowdown in the LNG sector in the bank market, is the $2.8 billion financing completed by Cheniere Energy Partners in February to refinance existing debt at Cheniere Creole Trail and redeem bonds issued by Sabine Pass LNG LP. In the power sector, a number of financings for gas-fired power plants were done, such as the $753 million facility for the 785 MW Towantic project in Connecticut, jointly owned by Competitive Power Ventures and GE Energy Financial Services, and the approximately $1.0 billion financing for the 1,485 MW Lackawanna Energy Center project in Pennsylvania owned by Invenergy and First Reserve that closed at the very end of the year. Project finance activity in the term loan B market also appears to have declined in 2016. Term loan B financings have historically been available primarily to support M&A activity or refinancings with respect to existing assets. An example of such a transaction is the approximately $1.0 billion term loan B facility relating to the 943 MW Linden cogeneration plant in New Jersey that closed in June and was reported to have been repriced in December. But while term loan B investors favor existing assets, the market may also be available for new construction in certain cases. In the fixed-rate project bond market, including private placements with insurance companies and other institutional investors, demand is reported to remain strong. A bond take-out is often an interesting option for sponsors after an initial construction period. For instance, in July, Freeport LNG issued $1.25 billion of investment-grade project bonds due 2038 to refinance some of the bank loans incurred in connection with the development of Freeport’s second liquefaction train. Page 23 Looking ahead to the next twelve months, a number of factors may affect the evolution of the market. The transition to the new administration in Washington and the potential for significant tax reform create uncertainty with respect to financing structures for renewable energy projects. The modification or elimination of the production tax credit or investment tax credit could certainly have a chilling effect on the project finance market for renewable power, though many observers believe that the existing incentives may stay in place and may be allowed to expire over time as contemplated under current law. A reduction of the corporate income tax rate is also possible, which would render the accelerated tax depreciation deductions associated with renewable energy projects less valuable. The reaction of tax equity investors to an expected or actual decrease in tax rate will be an important factor in 2017 and could lead to structural changes with respect to tax equity financings while also affecting the supply of tax equity. More broadly, the administration’s stated desire to reduce regulatory constraints could also have a material impact on financial markets. The Dodd-Frank Act, the leveraged lending guidelines issued by various regulatory agencies in 2013 and other related reforms enacted in recent years, while not directly aimed at project finance lending, all had an impact on many of the most active participants in the project finance market. As with other policy proposals, much uncertainty remains at this point as to the timing, scope and nature of the changes that may be made to the existing regulatory environment. In the conventional power sector, the combination of reduced capacity prices at PJM’s annual capacity auction and the potential over-exposure to PJM by certain project finance lenders could dampen the enthusiasm for projects in that region. However, given the strong liquidity overall in the bank market and the institutional fixed rate market, sponsors of strong projects should continue to have ready access to capital. Increased activity should also be expected in emerging areas in 2017, such as securitization and other aggregation facilities for residential solar assets. Bankruptcy Developments in the Energy Sector While commodities prices started to rebound from the depths of February of 2016, that rebound was not enough to save a number of companies from bankruptcy. In fact, nine of the ten largest chapter 11 bankruptcies in 2016 related to commodity-based businesses of energy and mining, led by the solar business, Sun Edison, and which included coal companies, Peabody Energy and Arch Coal, and oil and gas companies, Linn Energy, Energy XXI, Breitburn Energy Partners, Halcon Resources, Paragon Offshore and Sandridge Energy. In 2015, many of these companies had tried to stave off chapter 11 by engaging in uptier debt exchanges in which unsecured debt was exchanged for new second lien debt at a discount when the market first started to dive. As many had feared, the debt exchanges did not prove to be enough given the degree of the price crash. The energy-related bankruptcy filings did not end there. The next tier of filings included a substantial number of energy or energy services companies including CHC Group, Abengoa Bioenergy US Holding, and Seventy Seven Energy. For many of these companies, the slow, but steady climb in prices was not enough and companies faced the choice of continuing to swim upstream or restructure their indebtedness through chapter 11. As an example, Seventy Seven Energy successfully restructured approximately $1.1 billion of bond debt through a prepackaged chapter 11 plan, converting that debt into the equity of the Page 24 reorganized company. Its pre-packaged plan also provided for the issuance of warrants to its junior noteholders and its equity holders. The successful restructuring ultimately paved the way for a merger announced before the end of the year with Patterson-UTI with an approximate value of $1.76 billion, more than twice the midrange value suggested in Seventy Seven’s chapter 11 plan evidencing newfound strength in the market. However, while certain restructured companies prospered, others that sought to restructure earlier in the cycle took a second run through chapter 11 to liquidate their businesses, including Hercules Offshore and Global Geophysical Services. Despite the price recoveries, markets (including day rates for drillers) had not moved enough to allow these businesses the runway they needed to reorganize. The plethora of chapter 11 cases that were filed also have provided a number of opportunities for strategic and financial investors to purchase discrete asset packages from troubled companies in bankruptcy, which have included SunEdison, Stone Energy and Azure Midstream among others. The disconnect that had existed between potential buyers, on the one hand, and potential sellers, on the other hand, earlier in the cycle began to recede in the second half of 2016 leading to active marketing processes in early 2017. As one would expect, the high number of chapter 11 cases also led to legal developments as well including a highly controversial decision in the Sabine Oil & Gas Corp. case in which the New York bankruptcy court determined that certain covenants in Sabine’s gas gathering agreements, as drafted (which is important to the analysis) were not covenants that “run with the land” under Texas law and therefore, the agreements in question could be rejected as executory contracts. Other companies in chapter 11, including Magnum Hunter Resources, Sandridge Energy, Emerald Oil, Penn Virginia and Quicksilver Resources seized upon the decision and utilized the same strategy in their chapter 11 cases. Texas bankruptcy courts reportedly looked for an opportunity to reach their own conclusion on this issue, but did not get the same chance to make a determination of their own. As noted above, commodity price weakness has also affected the power industry, something that we expect will continue to play out in 2017. The change of administration has breathed some life into the chapter 11 cases of legacy coal companies, providing a chance for them to raise money and emerge successfully from chapter 11. This will also likely affect the prospects for other power companies that have been considering their options. Lastly, as noted above, the Energy Future Holdings bankruptcy continues into 2017 after the PUCT nixed the first EFH plan premised on the REIT transaction with Hunt Consolidated, and then the Third Circuit Court of Appeals changed the course of the EFH cases a second time when it ruled that EFH’s first lien and second lien noteholders were entitled to the make-whole payments provided under the senior note indentures. In early 2017, EFH will seek to confirm its plan, which provides for ONCOR to be sold to NextEra Energy under the terms of the current plan. TCEH, now known as Vistra Energy, emerged from bankruptcy separately from EFH in October and went back to the market in December looking to fund a dividend distribution transaction that would add leverage to Vistra’s retail operation and coal plant portfolio according to industry sources. Page 25 Environmental Regulation Going into 2017, the power sector is facing uncertainty regarding the continuation of major regulatory requirements promulgated and policies implemented during the Obama Administration. The new administration has promised to unravel most of these requirements and polices, and significantly reduce EPA’s regulatory presence. The seemingly diametrically opposed environmental policies of the out-going and in-coming administrations likely will result in a rapidly shifting regulatory landscape that may prove difficult to navigate in the coming months and years. While the new administration is in its infancy and has not yet announced how it plans to fulfill its promise to reduce regulatory burdens, there are a number of regulations that are likely to be targeted for repeal or modification, including:  WOTUS Rule. In June 2015, the EPA and the U.S. Army Corps of Engineers finalized a rule intended to clarify the meaning of the term “waters of the United States,” which establishes the scope of regulated waters under the Clean Water Act. Absent Congressional action or the agencies’ withdrawal of the rule, and if the rule is upheld by the courts, it is expected to expand federal jurisdiction under the Clean Water Act. The rule has been challenged by numerous states and industrial groups and some environmental groups, and its effectiveness has been stayed by federal courts.  Climate Regulations for New Power Plants. In October 2015, EPA finalized new source performance standards (“NSPS”) for greenhouse gas (“GHG”) emissions from new, modified, and reconstructed power plants under Section 111(b) of the Clean Air Act. The GHG NSPS are a legal prerequisite for the Clean Power Plan, which sets GHG emission standards for existing power plants under Section 111(d) of the Act. Numerous state and industry groups are challenging the rule, while other states, environmental and nonprofit groups, and some utilities have intervened on behalf of EPA to help defend the rule. Oral argument is scheduled for April 2017 in the U.S. Court of Appeals for the D.C. Circuit. Should the Trump Administration decide to stop defending the rule, or take other action to overturn or withdraw the rule, this could impact the future of both the GHG NSPS and the Clean Power Plan.  The Clean Power Plan. In October 2015, EPA finalized performance standards for GHG emissions from existing power plants under Section 111(d) of the Clean Air Act. Referred to as the Clean Power Plan, the standards are the centerpiece of the Obama Administration’s climate policy. Numerous state and industry groups are challenging the rule, while other states, environmental and nonprofit groups, and some utilities have intervened on behalf of EPA to help defend the rule. The U.S. Court of Appeals for the D.C. Circuit heard argument on the rule in September 2016, and is poised to issue a decision on pending challenges -- a ruling that ultimately may be advisory if the Trump Administration repeals or significantly modifies the standards. Implementation of the standards remains stayed by order of the U.S. Supreme Court. Page 26  Regional Haze Rule. In January 2017, EPA finalized revisions (“Revision Rule”) to the Regional Haze Rule which was passed to improve visibility, or visual air quality, in national parks and wilderness areas across the country. The Regional Haze Rule requires that states, in coordination with the federal government, develop and implement air quality protection plans every ten years to reduce the pollution that causes visibility impairment. The Revision Rule is a double-edged sword as it provides a much needed extension of the deadline for states to submit implementation plans for the second planning period from 2018 to 2021, but also memorializes unlawful interpretations that greatly expand the scope of the visibility program requirements. The Revision Rule is not impacted by the Administration’s recent regulatory freeze, but it is possible that Congress could vacate the rule using the Congressional Review Act. Petitions for judicial review of the Final Rule must be filed in the U.S. Court of Appeals for the District of Columbia Circuit by March 13, 2017. Actions by the Trump Administration on these and other regulatory requirements are certain to be met by fierce opposition by the environmental community and certain states. The Trump Administration can effectuate some changes in existing environmental programs through administrative guidance and enforcement practices, but it cannot repeal or modify regulatory requirements without going through the notice-and-comment rulemaking process. This process typically takes two years and almost always is followed by protracted rulemaking challenges. Given that environmental groups have vowed to “sue baby, sue,” it likely will be several years before there is final resolution of key regulatory requirements for the power sector. FERC Introduction On January 26, 2017, Norman C. Bay, who was Chairman of the Federal Energy Regulatory Commission (“FERC”), submitted his resignation to President Donald Trump effective February 3, 2017. Prior to Bay’s resignation, President Trump had appointed Commissioner Cheryl A. LaFleur as Acting Chairman of the FERC. LaFleur previously served as Acting Chairman from November 2013 to July 2014 and as Chairman from July 2014 until April 2015. There are now only two Commissioners serving on the five-member FERC – Acting Chairman LaFleur and Commissioner Colette D. Honorable, both Democrats appointed by former President Barack Obama. Two vacancies on the FERC had previously been created with the retirements of Republican Commissioners Phillip D. Moeller and Tony Clark in October 2015 and September 2016, respectively, which went unfilled through the end of the Obama Administration. In addition to these three unfilled seats, Commissioner Honorable’s term will expire in June 2017. This gives President Trump a unique opportunity to significantly change the makeup of the FERC during his first year in office. At a minimum, President Trump will appoint three new Republican Commissioners early in his term, one of whom will be designated as Chairman. All of the appointed Commissioners must be confirmed by the U.S. Senate. With the change in the makeup of the Commission, it is anticipated that FERC’s policy priorities also may shift. Throughout the campaign, President Trump articulated his interest in Page 27 infrastructure development, regulatory reform, and job creation and it is likely that his appointees will share and implement that vision. This could lead to a greater emphasis at FERC on expedited project reviews and approvals and a reduction in the regulatory burden imposed on regulated entities and certain transactions subject to FERC’s jurisdiction. It is less clear whether the new Republican Commissioners will attempt to make significant changes to FERC policies that address the operation of competitive wholesale markets and encourage the entry of new market entrants. Until a third Commissioner is confirmed, however, FERC lacks a quorum to issue substantive orders or policy pronouncements. To ensure that FERC will continue to function as efficiently as possible given the lack of a quorum, the FERC issued an order delegating additional authority to its staff on February 3, 2017. Among other things, the delegation order enables FERC staff to preserve the agency’s ability to review rate and tariff filings by granting delegated authority to issue suspension orders applicable to all submitted filings until the FERC once again has a quorum. The delegation order does not include the authority to approve major natural gas pipeline projects or contested rate and tariff filings. Major FERC developments and initiatives from 2016 and early 2017 are summarized below. FERC Market Rule Initiatives in 2016 FERC Addresses Common Control and Passive Investor Arguments In January 2016, FERC issued an order clarifying its policy as to when affiliated companies will be found to be under “common control” pursuant to 18 C.F.R. § 35.36(a)(9) and also confirming that passive investor status does not relieve investors in FERC-jurisdictional assets of applicable reporting obligations, including the requirement to file a notice of change in status. See Backyard Farms Energy LLC, 154 FERC ¶ 61,036 (2016). Backyard Farms Energy LLC and Devonshire Energy LLC (collectively, the “MBR Entities”), filed a petition for declaratory order asking that they should not be deemed affiliates or under common control with either (a) the funds and accounts managed by Fidelity Management & Research Company or its affiliates and subsidiaries (“Fidelity Accounts”) or (b) the funds and accounts managed by FIL Limited (“FIL”) or its affiliates and subsidiaries. The entities managing the Fidelity Accounts (“Fidelity Advisers”), FIL, and the MBR Entities are all indirect subsidiaries of FMR, LLC (“FMR”). The Fidelity Accounts consist of a family of mutual funds, commingled pools and several types of managed funds and accounts for institutional and retail clients. Because the Fidelity Accounts are owned by various shareholders, institutions or other clients of the Fidelity Accounts, and because FMR was not involved in their day-to-day management, the MBR Entities argued that they should not be deemed affiliates of the MBR Entities or under common control. Rejecting this argument, FERC emphasized that regardless of the ownership of the Fidelity Accounts, the Fidelity Advisers manage and control the investments that the Fidelity Accounts make and also exercise voting rights for the mutual funds in some circumstances. FERC stated that the agency’s focus for purposes of determining affiliation is “whether the Fidelity Advisers directly or indirectly own, control, or hold with power to vote, the outstanding voting securities Page 28 of any public utility or holding company in which Fidelity Accounts may invest.” Backyard Farms at P 21. With regard to FIL, the parent company of a financial services group specialized in management, administration and distribution of collective investments, institutional management, and retirement services, FERC held that, at the very least, the “significant degree of cross ownership . . . as well as two common directors” between the MBR Entities and FIL is indicative of common control. Id. at P 22. In the Backyard Farms order, FERC also rejected the MBR Entities’ argument in the alternative, finding that the “passive investor” exemption under the Public Utility Holding Company Act of 2005 is not applicable in the market-based rate context and therefore could not provide a basis to excuse applicants from filing required notifications of change in status. See id. at P 23. Similarly, FERC distinguished the blanket authorizations under Section 203 of the Federal Power Act for investment funds to purchase, acquire, or take any security in a public utility company in the ordinary course of business, as fiduciaries, and not with the purpose or with the effect of changing control of the company, see 18 C.F.R. § 366.3(b)(2)(i), because those blanket authorizations were granted subject to ongoing reporting requirements and investment limitations. Final Rule to Mandate Reliability Standard for Supply Chain Risk Management On July 21, 2016, FERC issued Order No. 829, a final rule that requires the North American Electric Reliability Corporation (“NERC”) to develop a Reliability Standard addressing security controls for supply chain management applicable to industrial control system hardware, software, and services associated with bulk electric system operations. The final rule identifies four minimum security objectives that the plans required by the Reliability Standard should address: (1) software integrity and authenticity; (2) vendor remote access; (3) information system planning; and (4) vendor risk management and procurement controls. Commissioner LaFleur dissented from the order, asserting that that the final rule should have had more notice and greater opportunity for stakeholder input. Under the first objective—software integrity and authenticity—the Commission requires that NERC’s Reliability Standard address verification of software publishers and the integrity of software and software patches prior to installation. Under the second objective—vendor remote access—NERC’s eventual Reliability Standard must address logging and control of vendorinitiated remote access sessions. Under the information system planning objective, the Reliability Standard must address how a responsible entity includes security considerations in the course of information-system planning and system development, while also addressing how a company identifies and documents risks from planning and development actions. Finally, with regard to the vendor risk management and procurement controls objective, the Reliability Standard must address provisions for, and verification of, security concepts in contracts, including vendor event notification processes, vendor personnel termination notifications for employees with access to relevant systems, vulnerability disclosures, incident response activities, and “other related aspects of procurement.” Throughout Order No. 829, FERC cites to supply-chain risk management policies developed by the National Institute of Standards and Technology, suggesting that they may provide useful— Page 29 and essentially preapproved—elements for NERC to incorporate into its forthcoming Reliability Standard. The supply-chain Reliability Standard development process is currently before NERC, which solicited public comments from October 20 through November 18. NERC will consider those comments as it develops the proposed standard, which must be submitted to FERC for approval by July 29, 2017. Inquiry Regarding Cybersecurity of Bulk Energy System Control Centers On July 21, 2016, FERC issued a Notice of Inquiry (“NOI”) seeking input on multiple issues related to the need for, and the possible effects of, modifications to the Critical Infrastructure Protection Reliability Standards to address the cybersecurity of bulk electric system control centers. In the NOI, FERC pointed to a December 2015 cyberattack in Ukraine—which left 225,000 customers without power, while also rendering parts of the electric system inoperable after the attack — as an example of the vulnerability of interconnected electric networks. FERC sought input on possible modifications to address “(1) separation between the Internet and [bulk electric system] Cyber Systems in Control Centers performing transmission operator functions; and (2) the use of ‘application whitelisting’ for [bulk electric system] Cyber Systems in Control Centers.” In the second part of its inquiry, FERC sought input regarding the potential for unintended impacts from the proposed measures, including:  How isolation from the Internet may affect activities required by other Reliability Standards, whether logical isolation or physical isolation is a preferable cybersecurity approach, whether such a requirement would affect communications between transmission operators and reliability coordinators or other applicable entities, and whether one-way diodes would be reliable and appropriate for certain communications with Control Centers;  Whether Reliability Standards should be modified to require application whitelisting for all BES Cyber Systems in Control Centers, and if not appropriate for all systems, whether it is appropriate for certain devices or components of such systems. Comments in response to the NOI were due to the Commission on September 26, 2016. The Commission has yet to take action in response to the NOI or comments received. Inquiry Regarding Changes to Reviews of Transactions and Market-Based Rate Applications On September 22, 2016, FERC issued an NOI to explore whether FERC should revise its approach to assessing market power for transactions under section 203 of the Federal Power Act (“FPA”) and applications for market-based rate authority under FPA section 205. The NOI also sought comment regarding the scope of FERC’s review of transactions under section 203. The Page 30 changes discussed in the NOI have the potential to increase or decrease the regulatory burdens borne by parties that own, operate, and invest in FERC-jurisdictional utilities. In the NOI, FERC sought to determine whether its current analysis of transactions and marketbased rate applications effectively identifies potential market power issues and, if not, what improvements can be made. Specifically, FERC sought comment on:  whether FERC should more precisely define de minimis in the context of its analysis of competition under section 203 and develop a specific test for determining when a proposed transaction meets that definition such that a full Competitive Analysis Screen is unnecessary;  whether FERC should add a requirement that applicants provide a supply curve analysis to analyze their transaction’s effect on competition under section 203;  whether there is a need to modify the existing pivotal supplier analysis in reviewing a market-based rate application;  whether adding a pivotal supplier analysis and/or a market share analysis to section 203 applications would help detect market power issues;  whether FERC should specify how capacity covered by a long-term firm PPA should be attributed in the section 203 Competitive Analysis Screen; and  whether to adopt a requirement that section 203 applicants submit certain mergerrelated documents, such as the reports that applicants submit to the Department of Justice and the Federal Trade Commission assessing the competitive effect of the merger. In the NOI, FERC acknowledged that there has been substantial change in the energy industry since it issued the blanket authorizations that exempt certain classes of transactions from FERC approval. FERC, therefore, sought comment on whether there are additional classes of transactions, such as acquisitions and dispositions of non-controlling interests in public utility assets, that should qualify for blanket authorizations. FERC also requested comment on whether certain mergers, such as those below a certain dollar threshold, could be subject to a reduced level of scrutiny and expedited processing. On the other hand, FERC also sought input on whether it should no longer provide a blanket authorization allowing holding companies that own only exempt wholesale generators (“EWGs”) to acquire additional EWGs. Comments in response to the NOI were due to FERC on November 28, 2016. FERC action on this matter is currently pending. Final Rule Addressing Offer Caps in Organized Wholesale Markets On November 17, 2016, FERC issued a final rule (Order No. 831) revising its regulations regarding offer caps on incremental energy offered in markets operated by Regional Transmission Organizations (“RTOs”) and Independent System Operators (“ISOs”). The final Page 31 rule is designed to improve price formation by ensuring that locational marginal prices (“LMPs”) are more reflective of resources’ true marginal costs, and by providing resources with a better opportunity to recover their short-run marginal costs. To accomplish these objectives, each RTO and ISO is required to adopt a uniform offer cap structure. Under the new rule, a resource may only submit an incremental energy offer equal to or above $1,000/MWh if the offer is cost-based (i.e., the offer accurately reflects the resource’s actual or expected short-run marginal costs). For an incremental energy offer equal to or above $1,000/MWh and less than or equal to $2,000/MWh, the RTO/ISO or Market Monitoring Unit must verify that the offer is cost-based before the RTO/ISO may use the offer to calculate LMPs. For an incremental energy offer above $2,000/MWh, the RTO/ISO or Market Monitoring Unit must also verify that the offer is cost-based, but offers in excess of $2,000/MWh will be capped at $2,000/MWh for purposes of calculating LMPs. Resulting LMPs, however, may exceed $2,000/MWh due to losses and congestion, and resources with verified cost-based incremental energy offers above $2,000/MWh are eligible to receive uplift. The final rule becomes effective on February 21, 2017. Each RTO and ISO is required to submit a revised tariff to within 75 days of the effective date, or by May 7, 2017. Proposed Rulemaking on Primary Frequency Response On November 17, 2016, FERC issued a Notice of Proposed Rulemaking (“NOPR”) proposing to require all new large and small generating facilities (both synchronous and non-synchronous) to install, operate, and maintain equipment capable of providing primary frequency response and to comply with proposed operating requirements. These requirements would be a required condition for new facilities interconnecting through both Large Generator Interconnection Agreements (“LGIAs”) and Small Generator Interconnection Agreements (“SGIAs”), and would be implemented through modification of the pro forma LGIA and SGIA. FERC proposes to define primary frequency response equipment as “the required hardware and/or software that provides frequency responsive real power control with the ability to sense changes in system frequency and autonomously adjust the generating facility’s real power output in accordance with the proposed maximum droop and dead band parameters and in the direction needed to correct frequency deviations.” The rationale behind adopting the new requirements is to improve upon the current limited frequency response requirements applicable to only synchronous facilities and extend the requirements to both non-synchronous and small generators. If the rule is finalized as proposed, it would apply to new generating facilities that execute an LGIA or SGIA, or request the filing of an unexecuted LGIA or SGIA, on or after the effective date of the final rule. Public utility transmission providers would have 60 days after publication of the final rule in the Federal Register to make the required changes to the LGIA and SGIA in their Open Access Transmission Tariffs. Non-public utility transmission providers would also be required to comply with the final rule as a condition of maintaining the status of their safe harbor tariff or satisfying the Order No. 888 reciprocity requirements. As part of the NOPR, FERC also requested comment on whether additional primary frequency response requirements are necessary for existing resources. Page 32 The comment period for the NOPR ends on January 24, 2017. Proposed Rulemaking to Promote Energy Storage, Distributed Resources On November 17, 2016, FERC issued a NOPR that would significantly expand the ability of energy storage resources and distributed energy resources to participate in wholesale electricity markets. As discussed below, FERC followed up this NOPR with a policy statement in January 2017 that provides guidance on cost recovery for electric storage resources. The November proposal, described as a “continuation of the [FERC’s] efforts to promote competition in organized wholesale electric markets by removing barriers to the participation of new technologies,” would require that RTOs and ISOs update their market rules to allow energy storage resources to sell all of the electric services they are technically capable of providing, including capacity, energy, and ancillary services. The NOPR would also require that RTOs and ISOs permit aggregators of distributed energy resources to participate directly in markets, while establishing rules for their participation. The impacts of both sets of provisions could be far-reaching. Energy-storage provisions would markedly increase the potential for a growing class of energy storage providers, ranging from flywheels and batteries to pumped-storage hydroelectric facilities, to more fully participate in— and receive payment from—organized energy markets. The NOPR would also provide enhanced wholesale market access for distributed energy resources, while providing for greater uniformity in treatment among RTOs and ISOs. The comment period for the NOPR ends on February 13, 2017. Proposed Rulemaking on Reforming the Large Generator Interconnection Procedures On December 15, 2016, FERC outlined in a new NOPR a series of proposed reforms to the Commission’s pro forma Large Generator Interconnection Procedures (“LGIP”) established by Order No. 2003, the pro forma Large Generator Interconnection Agreement (“LGIA”), the pro forma Open Access Transmission Tariff (“OATT”), and related regulations. The modifications aim to resolve concerns raised by interconnection customers and transmission providers, while better conforming FERC’s documents and procedures to the needs of changing generation resources, new technologies, and new state and federal policies. The NOPR is the latest outgrowth of a Petition for Rulemaking filed by the American Wind Energy Association in 2015. In the NOPR, the Commission proposes fourteen reforms in three separate categories:  Improve certainty by increasing predictability for interconnection customers through: (1) adopting revisions to the pro forma LGIP to require that transmission providers that conduct cluster studies move toward a scheduled and periodic restudy process; (2) revising the pro forma LGIA to permit interconnection customers to build a transmission provider’s interconnection facilities and network upgrades under a broader range of circumstances; (3) modifying the pro forma LGIA to require mutual agreement with the transmission customer in order for the transmission owner to elect Page 33 to initially self-fund costs of network upgrade construction; and (4) requiring that RTOs and ISOs establish processes to resolve interconnection disputes.  Improve transparency by requiring that transmission providers: (1) develop a method for determining contingent facilities in their LGIPs and LGIAs (pursuant to guidance provided in the NOPR); (2) make available the processes and assumptions underlying their system models; (3) post congestion and curtailment information on their Open Access Same-time Information System sites; and (4) comply with a new system of reporting requirements in order to gauge overall interconnection study performance. The NOPR also proposes to revise the definition of the term “Generating Facility” in the pro forma LGIP and LGIA to include electric storage resources.  Enhance interconnection processes by (1) allowing customers to request a level of interconnection service below a generating facility’s capacity; (2) allowing for provisional agreements so that customers can begin operations on a limited basis before the completion of the full interconnection process; (3) developing a process for interconnection customers to utilize surplus capacity at existing interconnection points; (4) establishing a separate procedure for transmission providers to assess the effect of changes in a customer’s technology without affecting the customer’s position in the interconnection queue; and (5) requiring transmission providers to evaluate their existing methods for modeling storage resources in interconnection studies and report to the Commission on the sufficiency of those models. The Commission also seeks input regarding: (1) the extent to which a cap on customer-borne network upgrade costs can “mitigate the potential for serial restudies” while avoiding an inappropriate shifting of cost responsibility; and (2) any “proposals or additional steps” the Commission could take to better resolve transmission-system issues that arise from proposed interconnections. Proposed Rulemaking to Improve Pricing for Fast-Start Resources On December 15, 2016, FERC proposed revisions to its regulations in a NOPR that would reform currently disparate approaches to fast-start resources and improve pricing to better reflect marginal costs for those resources. Each RTO and ISO currently employs its own unique method for pricing fast-start resources, some of which, the Commission states, may lead to unjust and unreasonable results. In the NOPR, FERC proposes that each RTO and ISO: (1) apply fast-start pricing to any committed resource that is able to start within 10 minutes, has a minimum runtime of one hour or less, and “that submits economic energy offers to the market” (i.e. that is not self-scheduling energy); (2) incorporate commitment costs (including start-up and no-load costs) of fast-start resources in both energy and operating-reserve prices; (3) treat fast-start resources as dispatchable from zero to their economic maximum operating limits when calculating prices (in order to remedy shortcomings in some markets that render fast-start units effectively unable to set prices); (4) ensure that only “feasible and economic” offline fast-start resources are permitted Page 34 to set prices for addressing certain system needs; and (5) incorporate fast-start pricing in both day-ahead and real-time markets. The Commission also proposes a new uniform definition of fast-start resources intended to allow both dispatchable and block-loaded resources—as well as both generation and demand-response resources—to qualify for fast-start treatment. In addition to soliciting comments on the proposed reforms to the pricing of fast-start resources, FERC seeks input on: (1) whether allowing fast-start resources to set prices could allow entities to exercise market power; (2) the time and effort necessary to update or modify software and models or otherwise implement the proposal; and (3) any other relevant considerations necessary to address the implementation of the proposed rulemaking. Proposed Rulemaking to Address Uplift Cost Allocation and Increase Uplift Transparency On January 19, 2017, FERC proposed revisions to its regulations in a NOPR that set forth preliminary new rules applicable to any RTO or ISO that allocates real-time uplift costs to market participants’ deviations from day-ahead market schedules (“deviations”), while also proposing greater transparency for uplift in general. Uplift payments are make-whole payments that cover the difference between a given resource’s offer price and the revenue it earns in the market when it is committed or dispatched for non-economic reasons. Real-time uplift, as defined in the NOPR, is a subset of uplift that applies only to resources committed after the close of an ISO’s or RTO’s day-ahead market. As explained in the NOPR, most RTOs and ISOs allocate at least a portion of real-time uplift costs to deviations from day-ahead market schedules. The NOPR proposes several new requirements for allocation of real-time uplift costs to better align with cost causation. First, RTOs and ISOs must distinguish between real-time uplift costs incurred for (1) system-wide capacity reasons; and (2) congestion management reasons. Within each of these real-time uplift categories, RTOs and ISOs must distinguish between deviations that help to address system needs and deviations that harm efforts to meet system needs, and then allocate costs to participants’ net harmful deviations. FERC also proposes that no real-time uplift costs be allocated to deviations that result from RTO- or ISO-initiated real-time dispatch instructions. Each real-time uplift allocation to deviations must be settled through hourly uplift calculations. The NOPR also contains a series of requirements to improve transparency for uplift, as well as for operator-initiated resource commitments. FERC proposes that RTOs and ISOs (1) report uplift payments for each transmission zone by day and uplift category; (2) report, on a monthly basis, total uplift payments for each resource; and (3) report the megawatts of operator-initiated commitments in (or near) real-time and after the close of the day-ahead market, with commitments broken-out both by transmission zone and by the purposes for which the commitments were undertaken (including, for example, voltage-support and capacity-related purposes, among others). In addition, FERC proposes to require that RTOs and ISOs define in their tariffs any transmission-constraint penalty factors, including providing the circumstances under which penalty factors can set locational-marginal prices and the procedures for temporarily changing them. According to FERC, the transparency provided by these reforms will improve Page 35 market efficiency and enhance the ability of market participants to assess RTO and ISO practices. Policy Statement on Concurrent Cost- and Market-Based Recovery for Electric Storage On January 19, 2017, FERC issued a policy statement that provides guidance and clarifies precedent related to cost recovery for electric storage resources. The Policy Statement specifically establishes the ability of electric storage resources to concurrently provide separate services at — and seek to recover costs through — both cost-based and market-based rates. The Policy Statement also considers matters raised during and after a November 9, 2016, technical conference on that topic. FERC’s Policy Statement addresses three main concerns raised in prior proceedings:  First, double recovery of costs by storage resources can be avoided by crediting market-based revenues back to cost-based ratepayers. This can be accomplished by either (1) recovering the full cost of the storage facility through the cost-based rate, but crediting all market-based revenues to cost-based customers; or (2) offsetting the revenue requirement used to develop the cost-based rate by the anticipated marketbased revenues.  Second, FERC states that it does not share commenters’ concerns regarding adverse market impacts. Instead, it analogizes allowing multiple revenue streams for storage resources to the multiple revenue streams already available to generation resources and vertically integrated utilities. FERC also states that price-suppression concerns can be addressed either in the same manner as double recovery concerns or by determining which costs go into cost-based rates.  Third, regarding independence of market participants from RTOs and ISOs, FERC states that some amount of coordination between storage resource owners or operators and ISOs or RTOs will be necessary. When cost-based services must be provided, RTO or ISO dispatch should receive priority, with penalties for any failure to perform. However, market-based services should be implemented according to parameters provided by resource owners or operators, just as is the case for other market participants. Commissioner LaFleur dissented from the Policy Statement. Although she remains open to storage resources receiving both cost-based and market-based revenues, LaFleur noted that the Policy Statement provides no guidance on how FERC will evaluate particular filings with respect to adverse market impacts. Moreover, she voiced concern that, although nominally limited to storage resources, the Policy Statement could be read to reflect FERC’s views on ongoing and complex discussions relating to broader multiple-payment-stream issues, including state policy initiatives. Page 36 Supreme Court Decisions Addressing FERC’s Jurisdiction FERC v. Electric Power Supply Association, 136 S. Ct. 760 (2016). In recent years, FERC has sought to regulate price fluctuations in wholesale markets and improve reliability by encouraging consumers to reduce their consumption of electricity during periods of peak demand. In 2011, FERC issued Order No. 745, which required wholesale market operators to compensate demand response providers in the same way they compensate generators who sell power in wholesale markets so long as the demand response resource provided “net benefits” (i.e., the resource would actually reduce costs for wholesale purchasers). Order No. 745 also required wholesale purchasers, who benefit from the lower prices demand response creates, to share proportionately the cost of demand response payments. The Electric Power Supply Association and others (collectively, “EPSA”) challenged Order No. 745, arguing that FERC lacked the statutory authority to regulate what they considered retail market activity. EPSA also asserted that FERC failed to adequately consider reasonable objections to the practice of compensating demand response resources at the same rate as wholesale providers. The U.S. Court of Appeals for the D.C. Circuit agreed with EPSA, concluding that demand response is “part of the retail market” because it “involves retail customers, their decision whether to purchase at retail, and the levels of retail electricity consumption.” The D.C. Circuit also found that Order No. 745 was arbitrary and capricious because it failed to address “reasonable (and persuasive) arguments” that Order No. 745 would result in unjust and discriminatory rates by overcompensating demand response resources. On January 25, 2016, in a 6-2 opinion delivered by Justice Kagan, the Supreme Court of the United States (“Supreme Court”) upheld Order No. 745, finding that FERC has the authority to regulate compensation of demand response bids in the wholesale market. The Court held that FERC has authority under the Federal Power Act to regulate any practice that “affects” wholesale power markets, so long as the effect is sufficiently “direct” and does not regulate retail rates. The Supreme Court also held that “FERC regulation does not run afoul of [the FPA] just because it affects—even substantially—the quantity or terms of retail sales.” On the contrary, “[w]hen FERC regulates what takes place on the wholesale market, as part of carrying out its charge to improve how that market runs, then no matter the effect on retail rates, [the FPA] imposes no bar.” The Supreme Court also rejected the D.C. Circuit’s finding that FERC’s decision to compensate demand response providers at the same price paid to generators was arbitrary and capricious. Hughes v. Talen Energy Marketing, LLC 136 S. Ct. 1288 (2016) State energy initiatives designed to support new generation and existing resources through price guarantees are increasingly subject to challenge at the FERC and in state and federal courts, including at the U.S. Supreme Court. Incumbent generators have alleged that these types of state programs are impermissible because they allow participating generators to distort price signals in wholesale capacity and energy markets subject to FERC’s jurisdiction. The outcome of, and reactions to, the legal proceedings could have significant market implications because, in the Page 37 absence of these state initiatives, new generation resources may have difficulty entering the market and existing resources may no longer be competitive enough to remain in the market. The most high-profile challenge to a state energy program, which was decided by the Supreme Court on April 19, 2016 in Hughes v. Talen Energy Marketing, LLC, involved an effort by the State of Maryland to incentivize the construction of new generation within the state. The Maryland Public Service Commission required three electric distribution companies to enter into long-term agreements with a new generator that would effectively guarantee the price the generator received for both capacity and energy sold in the wholesale markets operated by PJM Interconnection, LLC (“PJM”). The agreements were structured as “contracts-for-differences” which ensured that the generator received payments to make up any shortfall between the contract price and the PJM market price. Each utility would then pass on the costs associated with the long-term agreement to its ratepayers. The Court determined in Hughes that the Maryland program violated FERC’s authority over wholesale rates under the Federal Power Act because the contract guaranteed the generator a rate for capacity which was separate and distinct from the capacity clearing price that CPV Maryland would receive in the PJM capacity market. The Court’s conclusion that the Maryland program was setting wholesale market rates rested on the fact that CPV Maryland was paid only if its offer cleared in the PJM capacity market. The Court clarified, however, that states remain free to encourage new generation through measures such as tax incentives, land grants, and direct subsidies, provided those measures do not “condition the payment of funds on capacity clearing an auction” regulated by FERC. Market participants also have begun to challenge proposals designed to support existing generation resources. In particular, a recent decision by the Ohio Public Utilities Commission (“Ohio PUC”) to allow subsidiaries of American Electric Power (“AEP”) and First Energy to enter into Power Purchase Agreements (“PPAs”) with affiliated generators has generated controversy because the costs of the PPAs (net of capacity and energy sales in the PJM market) are recovered through non-bypassable charges assigned to retail rate customers. In addition to challenging the Ohio PUC’s decision in state proceedings, a coalition of existing generators has filed a complaint at FERC alleging that the PPAs, as backed by the non-bypassable retail rate charges, will distort prices in PJM by permitting allegedly out-of-market generators to participate in the market without regard to recovering their costs. This coalition of generators has requested that FERC subject the AEP and First Energy generation affiliates to offer price mitigation to “prevent the artificial suppression of prices in the [PJM Capacity Market] by below-cost offers for existing resources whose continued operation is being subsidized by State-approved out-ofmarket programs.” The fate of state-supported generation initiatives could have significant impacts on organized wholesale markets as these programs can determine, in part, which resources participate and clear in the market. While Hughes provided additional guidance to states developing new programs by drawing a line at whether the state subsidies are tied to the generator clearing its capacity and energy in the market, this division of authority still leaves room for argument as to whether a particular state program is permissible. Given the number and diversity of state incentive programs and proposals, market participants are likely to continue to contest state actions that benefit new and existing generation resources. Page 38 Post-Hughes Developments: Coalition For Competitive Electricity, et al. v. Zibelman, et al., No. 1:16-cv-08164 (SDNY) New York State’s Zero Emission Credit (“ZEC”) is the latest state-level initiative to face legal challenge. On October 19, 2016, a group of generation owners with holdings in New York State joined with the Coalition for Competitive Energy and the Electric Power Supply Association in an effort to halt the ZEC, a program which the NYPSC developed to provide financial support to nuclear power plants otherwise expected to close in whole or in part due to unprofitable economic conditions. The NYPSC framed the ZEC program as a necessary step to prevent backsliding in the State’s efforts to accomplish a 40% greenhouse-gas reduction and meet a 50% renewable target by 2030. Plaintiffs, however, argue (1) that the ZEC is preempted by federal jurisdiction over wholesale energy markets pursuant to the FPA; and (2) that it causes wholesale-market distortions such as artificially low prices, which impede power imports from outside of New York, in violation of the dormant Commerce Clause. Plaintiffs further argue that the ZEC differs from permissible state-level incentives like renewable energy credits because the value of the ZEC — which is calculated in part based on energy and capacity prices—is impermissibly “tethered” to the wholesale price of electricity. The NYPSC has moved to dismiss the case on the grounds that the FPA provides no private right of action and because the complaint shows neither a violation of the FPA nor the dormant Commerce Clause. The NYPSC argues that plaintiffs should instead have filed a complaint at FERC. Parties — including intervenors Exelon Corporation and its subsidiaries, Constellation Energy Nuclear Group, LLC, R.E. Ginna Nuclear Plant LLC, and Nine Mile Point Nuclear Station LLC — filed briefs on the motion to dismiss in January; a decision on the motion is pending. FERC Enforcement Activities FERC Issues Notice of Proposed Rulemaking Regarding Data Collection for Analytics, Surveillance, and Market-Based Rate Purposes In July, FERC issued a NOPR addressing Data Collection for Analytics and Surveillance and Market-Based Rate Purposes (“Data Collection NOPR”). The Data Collection NOPR requires market-based rate (“MBR”) sellers and entities that trade virtual products or hold financial transmission rights (“Virtual/FTR Participants”) to report certain information about their legal and financial connections to other entities. FERC intends to consolidate its collection of certain information into a relational database, which would be populated by the information submitted by MBR sellers and Virtual/FTR Participants. FERC would require the information to be submitted in an extensible markup language (“XML”) format, and has developed a “data dictionary” that defines associated terms and values. With regard to specific reporting requirements, MBR sellers and Virtual/FTR Participants would be required to submit information regarding their Connected Entities. Connected Entities would include “affiliates,” as currently defined for purposes of the MBR requirements in FERC’s regulations, that are either: (i) an “ultimate affiliate owner” of the entity; (ii) an entity that Page 39 participates in FERC-jurisdictional organized wholesale electric markets; or (iii) an entity that purchases or sells financial natural gas or electric energy derivative products that settle off the price of physical electric or natural gas energy products. The definition of Connected Entity also would include traders employed by an MBR seller or Virtual/FTR Participant. In addition, each MBR seller and Virtual/FTR Participant would be required to report any entity with which it has an agreement that “confers control over an electric generation asset that is used in, or offered into, wholesale electric markets.” MBR sellers and Virtual/FTR Participants would be required to submit “changes in connection” within 30 days of the change. A change in connection would occur if an entity: (i) becomes a Connected Entity of a MBR seller or Virtual/FTR Participant; or (ii) ceases to be a Connected Entity of a MBR seller or Virtual/FTR Participant. For connections created by an agreement, FERC proposes to include a de minimis threshold of 100 MW for reporting a change in connection (e.g., entering into, terminating, or amending an agreement that results in the parties conferring control of 100 MW or more of generation). FERC also proposes substantial changes to the information that would be submitted by MBR sellers. When submitting a market power analysis, MBR sellers would only provide information on affiliates that: (1) are an “ultimate affiliate owner,” defined as the furthest upstream affiliate owner(s) in the ownership chain; or (2) have a franchised service area or MBR authority, or directly own or control generation; transmission; intrastate natural gas transportation, storage or distribution facilities; physical coal supply sources or ownership of or control over who may access transportation of coal supplies. In addition, where a MBR seller is directly or indirectly owned or controlled by a foreign government, the MBR seller must identify the foreign entity as part of its ownership narrative. Finally, with respect to any owners that a MBR seller represents to be passive, the MBR seller must affirm in its ownership narrative that its passive owner(s) own a separate class of securities, have limited consent rights, do not exercise day-to-day control over the company, and cannot remove the manager without cause. MBR sellers would no longer be required to submit corporate organizational charts. The Data Collection NOPR also includes requirements associated with initial baseline informational filings that would be required after a Final Rule is published, as well as requirements to timely update changes to the information submitted to FERC. The NOPR has been assigned Docket No. RM16-17. FERC Issues Guidance Regarding Effective Energy Trading Compliance Practices In November, FERC issued a White Paper entitled Staff White Paper on Effective Energy Trading Compliance Practices (“White Paper”). The White Paper provides examples of compliance practices that have been effective in detecting and deterring market manipulation, as well as those practices that have been ineffective. The White Paper notes that for any compliance program to be effective, the organization must have a culture of compliance, and that promoting a culture of compliance starts at the top with executive officers that are committed to compliance and demonstrate that commitment through action. Page 40 The White Paper observes that organizations with effective trading compliance programs often have compliance personnel with a variety of expertise, including legal, operations, risk management, and trading. However, those compliance personnel also must understand how the organization’s business units operate on a day-to-day basis, and be provided sufficient authority and resources to implement compliance procedures, report compliance failures, and remedy those failures or deficiencies without interference from the business units. In addition, the White Paper observes that an organization’s recruitment and hiring standards for energy traders and its compensation structure play important roles in ensuring that a compliance program is effective. According to FERC, it is important for an organization to hire traders that are able and willing to learn and adhere to the rules that apply to their trading activities, and to implement a trader compensation structure that incentivizes compliance, not just profitability. Once hired, traders must be provided frequent training to ensure that they are aware of any changes in rules or requirements that apply to them on a timely basis and do not become lax in their compliance obligations. The training program should be tailored to the organization’s specific trading activities and combine a variety of different training styles. The White Paper also emphasizes that an organization should have practices in place that allow it to monitor traders’ activities to identify potential misconduct. Organizations can reduce the risk of trader noncompliance by placing appropriate restrictions on their trading activities that are designed to limit the traders’ ability and incentives to manipulate or engage in other misconduct. Once an organization has identified areas of potential noncompliance and set rules and restrictions for its traders, the organization must monitor trading activities to ensure compliance with those rules and restrictions. Effective monitoring could include the use of automated surveillance tools or algorithms that analyze trade data and communications to identify potential compliance issues. Finally, it is important for organizations to assess the performance of their compliance programs on a regular basis. Regular evaluations help to (1) ensure that the program’s compliance tools continue to be effective; (2) uncover compliance gaps and failures; and (3) identify where updates are necessary. FERC Hydroelectric Initiatives In July, FERC and the U.S. Army Corps of Engineers executed a Memorandum of Understanding (MOU) to coordinate the agencies’ processes for authorizing construction and operation of non-Federal hydropower projects. The MOU — which updates an earlier FERCArmy Corps MOU executed in 2011 — establishes a framework for early coordination between FERC and the Army Corps to ensure timely review of and action on non-Federal hydropower development applications. The MOU establishes a two-phased, synchronized review that will evaluate the impacts of a proposed project through one coordinated environmental review addressing FERC licensing under the Federal Power Act and the Army Corps permitting under Clean Water Act Sections 404 and 408. In November, FERC issued a Notice of Inquiry (NOI) seeking comment on its policy governing license terms for hydroelectric projects. Section 15(e) of the Federal Power Act requires that Page 41 “new” hydroelectric licenses (i.e., relicenses) be issued for terms not less than 30 years or more than 50 years. For hydroelectric facilities located at non-federal dams, FERC generally issues 30-year licenses for projects with minimal improvements, 40-year licenses for projects with moderate improvements, and 50-year licenses for projects with extensive improvements. Through the NOI, FERC is requesting stakeholder comment on whether it should: (1) retain its existing license term policy; (2) consider measures implemented during the prior license term in determining the term of the new license; (3) adopt a 50-year license term as a default license term; (4) employ a quantitative cost-based analysis to inform license terms; and (5) allow settlement agreements to play a role in determining license terms. Given the administrative costs associated with the relicensing process, the resources needed to undertake relicensing, and the increased costs generally associated with new license terms, the NOI provides an opportunity for licensees to make the case for a FERC policy that generally provides for longer license terms (i.e., license terms of 50 years). Oil Pipeline Litigation The key development in this area is the D.C. Circuit’s decision in United Airlines, Inc. v. FERC, 827 F.3d 122 (D.C. Cir. 2016), which called into question FERC’s policy of granting an income tax allowance to Master Limited Partnerships, REITs and other pass-through entities that charge cost-based rates. In an earlier decision, ExxonMobil Oil Corp. v. FERC, 487 F.3d 945 (D.C. Cir. 2007), the Court had held that FERC properly attributes the income tax liability of a passthrough entity’s investors to the pipeline’s cost of service for ratemaking purposes. In United, the Court found that the FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated the FERC's order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. In December 2016, FERC issued a Notice of Inquiry (“NOI”) seeking comment on how it should implement the Court’s direction. The policy developed in the NOI proceeding will likely be applied in cost-based rate cases involving not only oil pipelines but natural gas pipelines and electric transmission providers. FERC also is turning greater attention to its rate-indexing methodology under which oil pipelines are granted a nearly automatic rate increase each July based on the change in the Producer Price Index for Finished Goods plus a fixed adder. FERC has developed policy through case-by-case adjudication in the past few years, but has now proposed regulations that would bar an increase if the pipeline’s revenues exceeded its costs by 15% or more in the prior 2 years. Under the proposed regulations, a pipeline also will not be permitted an index rate increase that exceeds its change in cost per barrel-mile over the prior 2 years by more than 5 percentage points, which would replace the current threshold of 10 percentage points. These regulations will likely bring certainty and decrease litigation over rate indexing issues that has proliferated over the past five years. On the other hand, FERC is proposing to increase the financial reporting required of oil pipelines by disaggregating costs and revenues on separate portions of the pipeline’s system. If enacted, these regulations may increase litigation but would focus that litigation on overrecovering pipeline segments rather than the type of omnibus complaint seen in past years. Page 42 In the next year, we expect FERC to grapple with issues such as the extent to which pipelines can use marketing affiliates to remarket capacity at unregulated rates, further refinement of the test for entitlement to market-based rates, and jurisdiction over intrastate pipelines that are part of multi-modal interstate transportation. Developments in the Regulation of Pipelines and Natural Gas Storage Facilities In 2016, there were a number of significant developments in the regulation of pipeline safety. First, in March 2016, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a NOPR updating safety requirements for natural gas pipelines, including those governing the risk-based integrity assessment, repair, and validation program that transmission pipelines must develop under PHMSA’s regulations, referred to as “integrity management.” In July 2016, PHMSA issued a NOPR intended to improve oil spill response readiness and mitigate effects of rail incidents involving petroleum oil and certain high-hazard flammable trains. The NOPR, amongst other requirements, expanded the applicability of and the requirements for comprehensive oil spill response plans. On October 3, 2016, PHMSA also issued an Interim Final Rule (“IFR”) to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property or the environment. The IFR addresses a provision of the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“PIPES Act”) that provides the agency the authority to impose emergency restrictions, prohibitions and safety measures on owners or operators of gas or hazardous liquid pipeline facilities to address safety concerns affecting multiple owners or operators. As a result of the Aliso Canyon natural gas leak incident of 2015, in December 2016, PHMSA issued an IFR that revises the Federal pipeline safety regulations to address safety issues related to downhole facilities, including well integrity, wellbore tubing, and casing. The IFR incorporates the American Petroleum Institute’s recommended practices 1170 and 1171 by reference into the pipeline safety regulations. These standards will directly apply to approximately 200 interstate facilities, and serve as the minimum federal standard for approximately 200 intrastate facilities. In addition, the IFR imposes certain reporting requirements on underground natural gas storage facilities. LNG FERC and the Department of Energy’s Office of Fossil Energy (“DOE/FE”) issued several orders approving the construction of LNG facilities and the exportation of LNG commodities, respectively, in 2016. Generally, regulatory developments in 2016 primarily focused on clarifying procedures surrounding applications for approval for export projects from FERC and DOE/FE. Further, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a ruling clarifying some issues relevant to the regulation of LNG exports, while leaving other questions unanswered. Federal authority over LNG export activities is divided between DOE/FE and FERC. DOE/FE is charged with reviewing applications to export natural gas commodities and FERC is responsible Page 43 for the review of the siting, construction and operation of facilities used for exports of natural gas, including marine LNG terminals. FERC is also the lead agency for conducting a review of the environmental impacts of an LNG export project under the National Environmental Policy Act (“NEPA”). The scrutiny with which DOE/FE will review an application to export LNG depends on the trade status of the country to which the LNG will be exported – i.e., whether the export will be to a nation that has in place a free trade agreement with the United States requiring national treatment for trade in natural gas (“FTA Country”) or to a nation that does not have such an agreement (“Non-FTA Country”). The Natural Gas Act mandates that applications for authority to export LNG to an FTA Country be deemed consistent with the public interest and be granted without modification or delay. As a result, it takes DOE/FE only a few months to process an application to export to an FTA Country whereas it can take several years for DOE/FE to process an application for exports to a Non-FTA Country. As of January 2017, 25 applications to export LNG to Non-FTA Countries, totaling 33.97 Bcf/d, remain pending before DOE/FE. For LNG projects subject to FERC’s jurisdiction, DOE/FE will wait to issue an export authorization until FERC has completed, and DOE/FE has reviewed, the NEPA analysis prepared for the associated LNG terminal project. In 2016, DOE/FE issued final authorizations to Sabine Pass, Cameron LNG, Lake Charles Exports/Lake Charles LNG, Magnolia LNG, Southern LNG, and Freeport to export LNG, totaling up to 6.17 Bcf/d, to NonFTA Countries after FERC completed its NEPA analysis of those projects. DOE/FE also issued orders approving exports of LNG to Non-FTA countries from various existing, small-scale LNG liquefaction facilities and Canadian export terminals that are not subject to FERC jurisdiction. Those authorizations were granted to Bear Head LNG, Pieridae Energy, Flint Hills Resources, and Carib Energy for a total volume of 0.824 Bcf/d. To date, DOE/FE has issued authorizations to export natural gas to Non-FTA Countries in a combined total volume of 16.99 Bcf/d. Additionally, DOE/FE denied requests for rehearing of orders it issued previously approving LNG exports from the Sabine Pass, Corpus Christi, and Cove Point LNG terminals, allowing environmental and other groups to challenge the agency’s decisions in federal court. In August 2016, DOE/FE published a notice in the Federal Register that sets forth procedures for the submission of information concerning in-transit shipments of natural gas returning to the country of origin. The notice clarified that in-transit shipments of natural gas – i.e., shipments that only temporarily pass through the United States before returning to their country of origin, or temporarily pass through a foreign country before returning to the United States – are not “imports” or “exports” within the meaning of Section 3 of the Natural Gas Act. Therefore, persons that engage in qualifying “in-transit” shipments need not obtain approval from DOE/FE before doing so. Notably, persons making such in-transit shipments will still be subject to monthly reporting requirements to ensure these movements meet the criteria defining in-transit shipments, and are tracked accordingly. This development could impact LNG projects in Canada, Mexico, and the U.S. that propose to use feedstock gas that is temporarily transported through another country. For its part, FERC approved proposals for the construction and expansion of several LNG export terminal projects in 2016, including the Golden Pass, Elba Island/Southern, and Magnolia LNG Page 44 projects, as well as an expansion of the previously-approved export facilities at the Freeport and Cameron terminals. In March 2016, FERC issued an order denying an application for approval of the Jordan Cove LNG export terminal and a related interstate pipeline facility connecting the terminal to the natural gas pipeline grid. FERC cited as the justification for its action the fact that the applicant had not held an open season or obtained signed precedent agreements in support of the pipeline portion of the project. In denying authorization, FERC stated that without precedent agreements to demonstrate market support, FERC could not make the necessary finding that the public need for the pipeline outweighed any harm to landowners caused by the potential exercise of eminent domain to condemn property for the pipeline project. FERC found that since it was denying approval of the pipeline supplying gas to the LNG export terminal, it was also appropriate to deny the application to construct the terminal itself. However, FERC noted that its denial of Jordan Cove’s application was without prejudice to the applicant re-filing its application once precedent agreements had been signed with customers. Following the issuance of the order denying the authorizations, the project proponents successfully entered into precedent agreements with customers for most of the pipeline capacity and filed for rehearing with FERC. In their request for rehearing, the proponents requested that FERC reopen the administrative record to allow for consideration of the new precedent agreements as support for the project. In December 2016, FERC denied Jordan Cove’s request for rehearing, finding that the project proponents had not demonstrated sufficient cause for FERC to reopen the record. As with previous projects, the proceedings concluded in 2016 continued to be characterized by sustained opposition from various interest groups raising a number of environmental issues. Specifically, opponents of the projects faulted FERC’s analysis, among other things, for failing to consider the impacts of natural gas production and greenhouse gas emissions that allegedly would be induced from the construction of the various LNG export projects. In each case, FERC responded that the analysis urged by the opponents of the export projects was beyond the scope of the analysis in which the agency was required to engage under NEPA and would require the agency to engage in speculation that would not be conducive to its decision-making process. In positive—albeit limited—decisions for proponents of LNG exports, the D.C. Circuit rejected environmental challenges to authorizations of export-related modifications and additions to several LNG facilities issued by FERC. Specifically, the D.C. Circuit issued three separate opinions styled Sierra Club v. FERC involving the Sabine Pass, Freeport, and Corpus Christi facilities, as well as an order styled EarthReports, Inc. v. FERC involving the Cove Point terminal. In those decisions, the court determined that FERC had adequately addressed arguments frequently raised by project opponents related to the environmental impacts of proposed LNG export terminals. The D.C. Circuit found that in approving the facilities related to the export terminals, FERC was not required to consider in its environmental analysis the petitioners’ claims regarding the environmental impacts arising from the increased domestic production of natural gas. The court found that such concerns “do not fall within [FERC’s] bandwidth,” because FERC lacks the legal authority to authorize LNG exports; that authority instead resides with DOE/FE. The court also rejected petitioners’ argument that FERC should have expanded the scope of its NEPA review to include cumulative environmental impacts of pending and approved LNG export projects throughout the entire United States, finding that limiting the cumulative impacts analysis to a localized area was appropriate. The court’s decisions in 2016 will likely shift the focus of litigation to related authorizations issued by DOE/FE for export projects. One such challenge to a DOE/FE order authorizing exports to Non- Page 45 FTA Countries from the Freeport terminal is scheduled for oral argument before the D.C. Circuit in February 2017 in Docket No. 15-1489. In 2015, the Federal Railroad Administration issued its first approval for the transportation of LNG by rail to the Alaska Railroad Corporation. The Alaska Railroad Corporation was granted a two-year permit authorizing it to transport LNG by rail in intermodal portable tanks in container-on-flatcar service. In 2016, the Alaska Railroad Corporation made its first shipments of LNG by rail. This was the first time LNG was shipped by rail in the United States. Additional applications for the transport of LNG by rail are pending. In 2016, Congress considered various legislation designed to affect the approval process for the export of LNG commodities under the Natural Gas Act. These proposals variously would have made the export approval process simpler, and in some cases more onerous, than the current regulatory framework. None of these proposals, however, was enacted into law during the 2016 legislative session. Following the 2016 elections, Republicans retained control of the U.S. House and Senate and captured the White House. The new administration is generally viewed as having a favorable disposition toward the energy sector and new legislative pushes to ease the regulatory burdens placed on the industry can be expected in the next Congress. CFTC The Commodity Futures Trading Commission’s (“CFTC”) implementation of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) has slowed in the past year. The majority of the required regulations have been adopted, such as transactional reporting, recordkeeping, and central clearing requirements for certain derivatives. Remaining regulatory initiatives are developing slowly, if at all. Following the 2012 judicial decision vacating the CFTC’s position limits regulations, the CFTC has proposed but not yet adopted new rules. Similarly, the CFTC has not extended clearing requirements to energy commodity derivatives. It also eliminated the requirement that end-users of swaps report their commodity trade options on Form TO, which had proven to be a complex undertaking involving significant uncertainty. Given the potential that the new Administration and Congress could repeal or materially diminish the Dodd-Frank Act, it seems unlikely that increased regulation of swaps will be a regulatory priority in the coming year. ERCOT/Texas Oncor In 2016, the Public Utility Commission of Texas spent much of its time addressing the disposition of Oncor Electric Delivery Company in connection with the EFH bankruptcy. The attempts by Hunt Consolidated and NextEra to acquire Oncor are discussed above, but they have triggered at least two substantive discussions at the PUCT that have broader implications for the Texas market. Page 46 First, the issue that scuttled the Hunt deal was the PUCT’s reluctance to provide clear guidance on whether the tax benefits of the proposed REIT structure would be retained by the investors or would have to be flowed back to Oncor’s ratepayers. Discussion of that issue in the Hunt/Oncor case triggered a broader discussion at the PUCT about the treatment of federal income taxes in the setting of rates. At the end of March 2016, the Commission opened a rulemaking to consider the recovery of federal income tax expenses in rates, but there has, to date, been no activity in that rulemaking proceeding. The topic received considerable attention in the Hunt/Oncor proceedings; but in the NextEra/Oncor proceedings, Commission Staff advised that the Commission not address the issue at this time and instead deal with it on a case-by-case basis in individual rate cases. It remains to be seen how the PUCT will ultimately handle this issue. Second, the two Oncor proceedings have generated discussion regarding “ring fencing” of utilities. The highly leveraged KKR acquisition of TXU Corp in 2007 was conditioned on a lengthy list of measures designed to isolate the regulated utility (Oncor) from any future bankruptcy. The PUCT credits those measures with preserving the value of Oncor despite the EFH bankruptcy. Not surprisingly, there are calls for any new acquisition of Oncor to be similarly conditioned on such ring fencing provisions. However, some parties have suggested that ring fencing conditions should be imposed on other Texas utilities as well. Alternative Ratemaking In 2015, the Texas Legislature passed a law requiring the PUCT to “conduct a study and make a report analyzing alternative ratemaking mechanisms adopted by other states and [making] recommendations regarding appropriate reforms to the ratemaking process in [Texas].” That report, prepared by Christensen Associates Energy Consulting, was completed in late May 2016 and filed with the PUCT in early June 2016. The report reviewed the advantages and disadvantages of nearly a dozen alternative rate making options and generated particular discussion of mechanisms to “decouple” transmission and distribution utility rates (designed to recover significant fixed costs) from kWh usage (which varies for a number of reasons), including mechanisms that rely more on fixed charges. In the end, in its report back to the Legislature, the PUCT concluded: “At this time, the Commission does not believe that ratemaking mechanisms for transmission and distribution utilities that operate within ERCOT are in need of major revision. In fact, the Commission believes that existing streamlined methods of recovery are generally achieving their intended purposes.” Distributed Generation 2016: Strong Growth for Distributed Generation As Regulatory Battles Continue In 2016, distributed generation utilizing renewable energy sources, including small-scale solar photovoltaic (“PV”) residential and commercial installations, continued to experience growth. The U.S. Energy Information Administration (“EIA”) reported in December 2016 that for the twelve months ending October 2016, residential distributed solar PV generation produced 10,121,000 megawatt-hours, compared to 6,748,000 for the previous twelve month period ending October 2015, an approximately 34% increase. For the twelve months ending October 2016, total distributed solar PV generation across all sectors totaled 18,870,000 megawatt hours, compared to 13,801,000 megawatt-hours for the previous twelve month period ending October Page 47 2015. As distributed generation grew in deployment in 2016, spurred in part by the extension of the federal production tax credit and the investment tax credit for solar and wind projects in late 2015, regulatory battles over net metering and other policies continued to be fought in state legislatures and before state public utility commissions. Regulatory Battles over Net Metering At the state-level, net metering and retail electric rate policies supporting the development of distributed solar generation experienced challenges in key states. Net metering allows an electric retail customer with distributed generation to receive a credit for electricity provided to the grid during those times when the output of the customer’s installation exceeds the customer’s demand. The value of the credit in most states is set at the per-kWh retail rate, so that the credit offsets the customer’s retail electricity purchases on a one-to-one per-kWh basis and surplus credits are typically rolled over month to month. Utilities in states with high distributed generation penetration such as Arizona, Nevada, and other states have challenged how the net metering credit is valued, claiming that it should be set at an energy-only, wholesale-type rate, instead of the higher retail rate which includes transmission and distribution components. Many utilities argue that the lower energy-only rate more accurately reflects the value of the product provided by the customer, reduces the revenue shortfall resulting from customers relying less upon retail electricity but still remaining connected to the grid, and lessens cross-subsidization by customers without distributed generation. Proponents of the retail rate claim that distributed generation creates value beyond just electricity by reducing dispatch of fossil fuel generation, lessening transmission congestion, and promoting grid reliability. Results before state utility commissions have been mixed for both sides. In Arizona, the Arizona Corporation Commission issued an order on December 20, 2016 ending retail rate net metering on a prospective basis for new solar customers of the major regulated utilities such as Arizona Public Service and Tucson Electric Power. The decision is not immediately effective, but will be implemented through rate cases filed individually by the utilities, and the rate cases pending before the Commission filed by Arizona Public Service and Tucson Electric Power will be subject to the new rules. Retail rate net metering is being replaced with two valuation methods: (1) resource comparison proxy, which values the energy relative to what the utility pays for utility-scale solar resources, and (2) the avoided cost wholesale-type rate methodology. Retail-rate net metering credits for existing customers are grandfathered for 20 years from the date of interconnection. Significantly, the order also permits utilities to establish a separate rate class for distributed generation customers. In Nevada, the Public Utilities Commission of Nevada’s (“PUCN’s”) decision in late 2015 to end retail rate net metering for all customers, including existing customers, led to substantial backlash in the form of lawsuits and a failed effort to restore retail rate net metering by referendum. By July 2016, the Governor’s energy task force recommended that a grandfathering provision be adopted in the 2017 legislative session to preserve retail rate net metering for existing customers. In September 2016, the PUCN rolled back part of its late 2015 order and approved a settlement among NV Energy, PUCN staff, residential solar developer Solar City, and other stakeholders grandfathering retail rate net metering for existing customers on a prospective basis starting December 2016 for a period of 20 years. Page 48 Approving grandfathering for existing customers was not the final chapter in Nevada for net metering in 2016. On December 22, 2016, the PUCN issued an order re-establishing the retailrate net metering program for new customers in the service territory of NV Energy subsidiary Sierra Pacific Power Company under a 6 megawatt total cap. The order, which is effective January 1, 2017, only affects customers in the northern part of the state where less distributed generation is concentrated. However, commentators in the press have suggested that the PUCN could consider a similar measure during the next rate case for NV Energy subsidiary Nevada Power, which serves the more populated southern part of the state. Nevada Power’s rate case is expected to commence in June 2017. 2017: A Look Ahead Net metering programs and other rate issues affecting distributed generation will likely be the centerpiece of major state-level proceedings in 2017. As noted above, utility rate cases, as opposed to general rulemaking proceedings, will be the grounds for contesting valuation issues for excess generation in Arizona and Nevada. In Hawaii, where caps for the “grid supply” program were reached in 2016, the Hawaii Public Utilities Commission has convened a comprehensive rulemaking proceeding to address the future of distributed generation, including how excess generation should be compensated. In New York, the “Reforming the Energy Vision” proceeding convened by the New York Public Service Commission is entering the next phase in which the Commission staff and participants will consider ratemaking policies to encourage deployment of distributed generation and provide utilities with adequate revenue streams in connection with operating platforms (Distributed System Platforms, or “DSPs”) for integrating, deploying, and maximizing the value and attributes of distributed generation. These and other proceedings likely mean that 2017 will be another year of significant regulatory developments affecting distributed generation. Energy Efficiency Over the course of its over forty year history, the provisions of the Energy Policy and Conservation Act (42 U.S.C. § § 6201-6422) which guide the DOE’s promulgation of energy efficiency standards for consumer appliances, commercial equipment, and other products have been interpreted relatively infrequently by the federal courts. On August 8, 2016, the U.S. Court of Appeals for the Seventh Circuit issued an opinion in Zero Zone, Inc., et al., v. U.S. Department of Energy, No. 14-2159 (7th Cir. Aug. 8, 2016), rejecting a challenge to new energy efficiency standards adopted by DOE for commercial refrigeration equipment. While many commentators have focused on this case because the court sustained DOE’s application of the “social cost of carbon” metric, it is also significant because it highlights the challenges in appealing energy efficiency standards. Distilling the basic standard of review under the Administrative Procedure Act, the court affirmed that its role was not to ensure that DOE adopted any particular outcome among potential options, even if the final rule was “questionable in the minds of some,” but instead whether DOE’s adoption of the standards was “supported by substantial evidence and was reached through a reasoned decision-making process.” Given the multi-phase rulemaking proceedings conducted by DOE and the substantial record typically compiled by the agency, potential challengers face a number of hurdles in Page 49 seeking judicial review of new or amended standards related to convincing a court that the agency did not consider a key issue or did not have evidence to support its conclusions. This challenge underscores an obvious, but important, lesson for companies whose products are subject to DOE energy efficiency standards: active participation at each stage of the proceedings before DOE - from submitting comments on the proposed testing procedures and product classes through participating in public meetings and commenting on the proposed standards - is critical to both effective advocacy before DOE during the rulemaking, as well as preserving the option of and setting the groundwork for seeking judicial review. On January 20, 2017, the White House issued a memorandum to federal departments and agencies directing them to institute a “regulatory freeze” on new regulations not yet effective and near-final rules. This “freeze” potentially applies to several final rules issued by the Department of Energy adopting new energy efficiency standards or test procedures for the following products: Ceiling Fans (standards), Dedicated-Purpose Pool Pumps (standards), Residential Central Air Conditioners and Heat Pumps (standards), Compressors (test procedures), Walk-In Coolers and Walk-In Freezers (test procedures), and Miscellaneous Refrigeration Products (test procedures). It also applies to several near-final rules that were still pending sign-off at the Office of Management and Budget or within DOE: Portable Air Conditioners (standards), Commercial Boilers (standards), Uninterrupted Power Supplies (standards), Walk-In Coolers and Walk-In Freezers (standards), and Manufactured Housing (standards and test procedures). Interested parties should closely monitor how the “regulatory freeze” memorandum is implemented with regard to these rulemakings. It is not assured that all of these energy efficiency standards and test procedures will be withdrawn or delayed pending further consideration. For example, while the memorandum directs departments and agencies to delay or withdraw rules already submitted to or published by the Federal Register, at least one Federal appellate decision has held that energy efficiency standards promulgated under the Energy Policy and Conservation Act cannot be withdrawn or delayed once published in the Federal Register without following formal notice and comment procedures. See Natural Resources Defense Council v. Abraham, 355 F.3d 179 (2nd Cir. 2004). Further, the Energy Policy and Conservation Act has timing requirements for the review and issuance of new standards, and the “regulatory freeze” memorandum acknowledges that the departments and agencies must comply with statutory timing requirements. Potential Tax Reform Under the Trump Administration Both President Donald Trump and the House Republicans have presented plans for tax reform— Trump on his campaign website (the “Trump Plan”) and the House Republicans through their “A Better Way” white paper (the “House Blueprint” and, together with the Trump Plan, the “Republican Proposals”). Although we can speak to the broad strokes of possible tax reform under the Republican Proposals, we can draw few definitive conclusions because important details of each plan are undeveloped and the differences between the two plans are unresolved. Tax reform timing Tax reform may occur relatively early in the new administration. The Trump campaign and many of the President’s appointees have promised early tax reform. Treasury Secretary nominee Page 50 Steven Mnuchin named it his “first priority.” Trump looks willing to compromise with the House Republicans over certain differences between the Republican Proposals. For example, the President revised the Trump Plan in September to more closely resemble the House Blueprint. Furthermore, new Senate minority leader Charles Schumer has expressed qualified support for certain proposed reforms, and Senate Republicans may seek to pass certain tax reform proposals through budget reconciliation procedures to avoid Democrat filibusters in the Senate. Lowering rates and closing “loopholes”: effect on pass-through entities and renewables The Republican Proposals would lower the corporate tax rate significantly (the House Blueprint proposes a 20% top marginal rate; the Trump Plan 15%). Although a lower corporate tax rate will not eliminate the benefit of doing business in pass-through entitles like MLPs and Scorporations, it will decrease the relative benefits of doing so. The Republican Proposals rely on closing “loopholes”—eliminating credits and deductions—to pay for the decrease in the corporate tax rate. However, specifics are lacking. The House Blueprint “generally will eliminate special-interest deductions and credits” other than the research and development (“R&D”) credit and certain individual tax deductions. The Trump Plan simply notes that it will “eliminate special interest loopholes,” also excepting the R&D credit. For the renewables sector, there is a risk that tax credits and deductions on which the sector heavily relies will be modified or eliminated under the Republican Proposals. Yet there are reasons to believe these credits might be spared. In 2015, a Republican-controlled Congress extended the PTC and the investment tax credit, among others. President Trump has been inconsistent on the matter. While he has been critical of renewable energy subsidies, he has also said he is “fine” with the PTC. Secretary of the Treasury, Steve Mnuchin, expressed support for the existing phase-out of the PTC during his Senate confirmation hearing. Even if the credits survive, their relative value and appeal to investors may decrease if the corporate tax rate is reduced. Possible elimination of the “carried interest loophole” The so-called “carried interest loophole” may be closed as part of the tax reform efforts. Generally, carried interest is the share of profits paid to the general partner of a private investment fund (often a private equity fund) regardless of whether the general partner contributed any initial capital, which share may be taxed at favorable capital gains rates on an exit event. President Trump promised to eliminate this “loophole” while on the campaign trail. And eliminating the special rates for carried interests may have bipartisan support. For example, Senator Schumer has previously called for its elimination. The House Blueprint is silent on the matter. Current expensing for capital investment: possible benefit for energy sector The Republican Proposals would adopt immediate expensing of capital investment, offset by disallowing the deduction of interest expense (under the House Blueprint, interest expense could still be deducted against interest income; under the Trump Plan, it is unclear). This could be a Page 51 tremendous benefit to capital-intensive businesses, such as those in the energy sector. The Trump Plan, however, restricts this benefit to “firms engaged in manufacturing in the US” and makes the expensing an election (revocable for the first three years). There is no guidance as to what firms would qualify as “engaged in manufacturing” under the Trump Plan. International tax: undistributed earnings may be taxed, but the rest is murky The Republican Proposals encourage firms to repatriate overseas earnings by taxing undistributed foreign earnings, whether or not repatriated. Under the Trump Plan, this tax would be an immediate 10% tax on all accumulated foreign earnings. The House Blueprint proposes an 8.75% tax on overseas cash and a 3.5% tax on all other overseas earnings payable over eight years. The Republican Plans otherwise diverge significantly. The Trump Plan, after the one-time tax, would continue to allow the deferral of tax on foreign earnings until repatriation. The House Blueprint, after the one-time tax, would eliminate taxes on foreign earnings entirely, providing a 100% dividend deduction for repatriated funds and a border adjustment tax (explained below). If Congressional Republicans are unable to garner enough support for this territorial international tax regime, they may push for continuing deferral. The House Blueprint would introduce a border adjustment tax that would tax imports and exempt exports. The resulting destination-based regime would levy taxes on goods based on where they are consumed (rather than where they are produced). The income of foreign companies from U.S. sales would face the same U.S. taxes that domestic companies currently pay; meanwhile, income from goods sold abroad by U.S. businesses would no longer be taxed by the U.S. (and reciprocally, expenses incurred abroad would no longer be deductible against U.S. income). However, the likelihood of such a tax is highly uncertain. The mechanics of its implementation have yet to be explained, and President Trump has criticized its complexity. A number of other barriers, including concerns about the transition and WTO compliance, further threaten the tax’s prospects. Net operating losses: rules may be reshaped The House Blueprint proposes changes to the net operating loss (“NOL”) rules. It would cap NOLs at 90% of income, eliminate carrybacks to prior years, and permit indefinite carryforwards. If implemented, the cap may negatively impact YieldCos, structures commonly used to finance renewables, because many rely heavily on the use of NOLs. The Trump Plan is silent on the matter. Mexican Power Market Continues to Develop Mexico’s newly liberalized power market continues to develop and provide opportunities for investors. The three regions of the Wholesale Electricity Market (Mercado Eléctrico Mayorista, or “MEM”) commenced operations in phases in 2016, first with the Baja California Interconnected System on January 27, 2016, then the National Interconnected System on January 29, 2016, and finally the Baja California Sur Electric System on March 23, 2016. According to the Energy Information Administration, the average prices in most locations during the market’s Page 52 first six months of operation ranged from 880 to 1,100 pesos per MWh, or about $48/MWh to $60/MWh. In addition, the Centro Nacional de Control de Energía (“CENACE”) held its first two auctions for long-term contracts for electricity, capacity, and clean energy certificates in 2016. The first long-term auction, held in March, resulted in 11 companies being awarded contracts to develop more than 1.8 gigawatts of new solar and wind capacity worth $2.1 billion. Through the second long-term auction, the results of which were announced in September, 23 companies were awarded contracts for 36 projects and Clean Energy Certificates representing 2,871 MW of new capacity worth $4 billion. The third long-term auction, announced in 2016, will be held in April 2017. On May 31, 2016, Mexico’s Secretariat of Energy (“SENER”) published the Development Program of the National Electric System (Programa de Desarrollo del Sistema Eléctrico Nacional, or “PRODESEN”), a document that contains the development plan for the National Electric System (“SEN”) with respect to generation, transmission, and distribution for 2016- 2030. The PRODESEN anticipates that, in order to meet demand from 2016-2029, the Mexican system will need nearly 60 GW of additional power and extensive investments in new transmission and distribution facilities. In total, SENER estimates that these projects will require an investment of $120 billion over the next 15 years. Given that private parties may now participate in the bidding process, these projects could offer a chance for investors to capitalize on the newly expanding Mexican power market. Exhibit A Selected Electric and Gas Utility Mergers and Acquisitions January 1, 2013 – February 10, 2017 Date Announced (Closed) Parties Total Transaction Value (Millions) Equity Value Consideration Premium to Market Price (days prior to announcement) P/E NTM Break-Up Fee (% of Equity Value) Reverse Break-Up Fee (% of Equity Value) Management Structure/Other Undertakings Required Regulatory Approvals Nature of Process 1/25/17 (pending) WGL Holdings/ AltaGas $6,324.34 $4,520.08 Cash 27.9% (11/28/16 unaffected) 26.2x $136M (3.0%) $205M, $182M or $68M (4.5%, 4.03% & 1.5%) Maintain headquarters in Washington, D.C.; WGL management to manage all AltaGas US operations HSR, FERC, CFIUS, DC, MD and VA Competitive 5/13/16 (pending) Westar/ Great Plains $12,193.75 $8,537.88 Cash 13.4% (1 day) 36.1% (3/9/16 unaffected) 25.0x $280M (3.28%) $380M (4.45%) Maintain headquarters in Topeka, KS; one Westar director to be appointed to board of combined company HSR, FERC, KS, NRC and FCC Competitive 2/9/16 (1/1/17) Empire District/ Algonquin $2,389.81 $1,487.95 Cash 21.3% (1 day) 23.2x $53M (3.56%) $65M (4.37%) Empire District management to head regional management team; no changes to management or employees at Empire HSR, FERC, CFIUS, AR, KS, MO, OK and FCC Competitive Date Announced (Closed) Parties Total Transaction Value (Millions) Equity Value Consideration Premium to Market Price (days prior to announcement) P/E NTM Break-Up Fee (% of Equity Value) Reverse Break-Up Fee (% of Equity Value) Management Structure/Other Undertakings Required Regulatory Approvals Nature of Process 2/9/16 (10/14/16) ITC Holdings/ Fortis, Inc. $11,426.90 $6,945.86 Cash/Stock 15.5% (1 day) 21.9x $245M (3.53%) $280M/$245M (4.03%/3.53%) Maintain headquarters in MI, no force reductions HSR, FERC, CFIUS, IL, KS, MO, OK and WI Competitive 2/1/16 (9/16/16) Questar/ Dominion $5,982.94 $4,396.74 Cash 23.2% (1 day prior) 19.1 $99M (2.25%) $154M (3.5%) One Questar representative to be appointed to each of Dominion and Dominion Midstream’s boards; maintenance of headquarters in Salt Lake City HSR, UT, WY, ID Bilateral 10/26/15 (10/3/16) Piedmont/ Duke $6,589.35 $4,794.90 Cash 40% (1-day prior) 30.9x $125M (2.61%) $250M (5.21%) One Piedmont representative will be added to Duke’s Board of Directors; an existing member of Piedmont’s management team will lead Duke’s natural gas operations. HSR, NC, FCC Competitive 9/4/15 (7/1/16) TECO/ Emera $10,422.48 $6,481.18 Cash 48% (unaffected price as of 7/15/15) 24.7x $212.5M (3.28%) $326.9M (5.04%) Tampa Electric and NM Gas to maintain existing headquarters in Tampa and Albuquerque HSR, CFIUS, FERC, NM, FCC Competitive Date Announced (Closed) Parties Total Transaction Value (Millions) Equity Value Consideration Premium to Market Price (days prior to announcement) P/E NTM Break-Up Fee (% of Equity Value) Reverse Break-Up Fee (% of Equity Value) Management Structure/Other Undertakings Required Regulatory Approvals Nature of Process 8/24/15 (7/1/16) AGL/ Southern $12,001.74 $7,924.74 Cash 36.3% (20-day VWAP) 21.8x $201M (2.54%) N/A AGL to maintain separate board and management team HSR, CA, GA, IL, MD, NJ, VA, FCC Bilateral 2/26/15 (12/16/15) UIL/ Iberdrola (USA) $4,847.02 $3,040.02 Stock/Cash 24.6% (est. 1- day prior) 21.6x $75M (2.47%) N/A UIL CEO to be CEO of combined entity; UIL CEO and 2 others to join Iberdrola (USA) board of directors HSR, CFIUS, CT, MA, FCC Bilateral 12/3/14 (terminated 7/16/16) HEI/ NextEra $4,567.39 $2,601.37 Stock 21% (est. 20-day VWAP) 15.9x $90M (3.46%) $90M (3.46%) HEI to maintain local headquarters and be managed locally HSR, FERC, HA, FCC Bilateral 10/20/14 (4/13/16) CLECO/ Macquarie/ BCIMC $4,703.54 $3,365.13 Cash 14.7% (1-day prior)(strategic process had been previously disclosed) 20.3x $120M (3.57%) $180M (5.35%) CLECO to maintain local headquarters and management; CLECO President to become CEO upon closing HSR, CFIUS, FERC, LA Competitive 6/23/14 (6/29/15) Integrys/ WEC $9,114.57 $5,684.47 Stock/Cash 17.3% (1 day prior) 19.5x $175M (3.08%) $175M (3.08%) 3 Integrys Directors to join WEC Board upon closing HSR, FERC, WIA, IL, MI, MN, FCC Bilateral 4/30/14 (3/23/16) Pepco/ Exelon $12,605.43 $6,912.43 Cash 19.6% (1 day prior); 29.5% (20-day VWAP) 22.4x $293M (4.24%) $180M (2.60%) Maintenance of local and regional headquarters and management HSR, FERC, DE, DC, MD, NJ, VA, FCC Competitive Date Announced (Closed) Parties Total Transaction Value (Millions) Equity Value Consideration Premium to Market Price (days prior to announcement) P/E NTM Break-Up Fee (% of Equity Value) Reverse Break-Up Fee (% of Equity Value) Management Structure/Other Undertakings Required Regulatory Approvals Nature of Process 12/11/13 (8/15/14) UNS/Fortis $4,343.11 $2,502.68 Cash 30.1% (1 day prior) 18.4x $63.9M (2.55%) N/A UNS management team to remain in place, UNS headquarters to remain in Tucson and 4 current directors of UNS to remain on UNS Board of Directors following closing HSR, CFIUS, FERC, AZ, FCC Bilateral 5/29/13 (12/19/13) NV/ Berkshire $10,688.83 $5,664.63 Cash 20.3% (1 day prior) 18.0x $56.6M (1st 6 weeks) (1.0%)/$169.7 M (3.0%) N/A NV to continue to operate as a separate subsidiary and maintain local headquarters HSR, FERC, NV, FCC Bilateral