February 15, 2016

TO: CLIENTS AND OTHER FRIENDS OF THE FIRM 2015 – Another Record Year for Energy Mergers and Acquisitions

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 2015 was, to Contributors: say the least, robust. The low interest rate environment and favorable James H. Barkley economic conditions that contributed to record deal volume in 2014 persisted Brooksany Barrowes into 2015. With the tailwind of economic conditions and interest rates, total Emil Barth transaction volume exceeded the all-time high watermark of $184 billion established in 2014 by almost $20 billion.1 By the end of 2015, approximately Megan Berge $202 billion of transactions had been announced. 2016 also is off to a fast start William M. Bumpers with roughly $20 billion of transactions announced in the first 6 weeks of the Michael Didriksen year. Jessica Fore More than half the 2015 activity involved pipelines, midstream companies and Jerrod Harrison MLPs. In that sector, deal volume maintained its robust activity, increasing Hillary H. Holmes slightly in 2015 to $133.3 billion as compared to 130.8 billion for 2014. Transactions among regulated electric utilities notched a similarly modest William S. Lamb increase, from roughly $30 billion in 2014 to almost $34 billion in 2015. Luckey McDowell Among LDCs, volume shot up from $3.4 billion to over $18 billion, driven by Steven R. Miles transactions involving AGL Resources and Piedmont Natural Gas Company. The value of transactions involving electric generation assets decreased, from Jay Ryan $12.3 billion to $8.1 billion, while the value of transactions involving Carlos Solé renewable generation assets increased to $8.5 billion in 2015 as compared to Timothy S. Taylor $7.5 billion in 2014. We offer additional commentary about key transactions and the general trends that we see in each of these subsectors below. Martin Toulouse Gregory Wagner Among regulated companies, the headline for 2015 was the premiums Elaine M. Walsh achieved by sellers. As the chart attached as Exhibit A shows, since 2013 premiums in regulated transactions have been rising, reaching unprecedented levels in 2015. During 2013 and 2014, premiums to market price prior to announcement tended to be in the range of the 15% to 21% (the UNS/Fortis transaction being the one exception). Valuations as a multiple of next twelve months earnings ranged from 15.9x to 22.4x. All of the transactions announced in 2015 exceeded these levels by almost every measure. The UIL transaction was at the low end of the range with a premium to market (as estimated by the companies) of 24.6% and a forward multiple of 21.6 times the

1 Source: SNL Financial, transactions with announced transaction values of $100 million or more.

Page 1

next year’s earnings. AGL, TECO and Piedmont all achieved higher valuations, with Piedmont in particular establishing a 40% premium to market and a forward multiple of 30.9x.2As Exhibit A shows, over the past three years, transactions have been about evenly split between competitive bidding and bilateral negotiations. Some might ask whether the nature of the process, competitive bidding versus bilateral negotiations, has an impact on acquisition price. On average, it does appear that higher valuations have been achieved in competitive processes, although substantial premiums have been achieved in bilateral negotiations too. The two transactions that achieved the highest multiples – Piedmont/Duke and TECO/Emera were both competitive processes, but the highest premium to market on the chart was the AGL/Southern transaction at 48%, which was a bilateral negotiation.

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 in other industries. Initially, these provisions were used to provide private equity buyers with a way to get out of a transaction if for some reason their 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, a reverse break-up fee creates a strong incentive for a buyer to work hard to obtain antitrust and other regulatory clearances for the transaction.

Until recently, 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. The reverse break-up fee typically would be triggered only in the event of a financing failure. Over the past two years, reverse break-up fees have become common in transactions involving regulated companies, beginning with the Pepco/Exelon transaction. In that instance, the reverse break-up fee was structured as a mandatory purchase by Exelon of a block of preferred stock that is redeemable by Pepco at its original purchase price in the event regulatory approval is obtained, and for no consideration if all regulatory approvals are not obtained. Since then, the WEC/Intergrys, Cleco/Macquarie/BCIMC, HEI/NextEra, TECO/Emera and Piedmont/Duke transactions have all 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 the TECO/Emera transaction. 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.

There are many factors that favor continued consolidation among electric, gas and power companies in the United States, just as there have been for many years. 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. Much of our national energy

2 The recently announced Questar/Dominion, ITC Holdings/Fortis and Empire District/Algonquin transactions raise the question of whether 2016 will bring a return to less lofty valuation levels. With premiums to market ranging from 15.5% to 23.2% and forward earnings multiples of 19.1x to 23.2x, these transactions seem more in line with transactions announced in 2014 and prior years than with 2015 deals.

Page 2

infrastructure is in the process of being rebuilt. Energy policy and consumer preference are driving a massive shift away from fossil fuels toward renewable resources. In many instances new renewable generation requires substantial investments in new high-voltage 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, the precipitous drop in oil and gas prices over the past two years is disrupting all aspects of energy supply, in the U.S. and around the world. 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 two years. Finally, the higher growth rates, lower levels of volatility in earnings of LDCs compared to regulated electric operations and the increased scarcity of pure play regulated gas companies has driven an unprecedented level of interest in LDCs.

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 2016 as likely to decrease from 2015 levels. Renewable assets continue to generate strong interest among YieldCos, strategic buyers and private equity, as a result of which we expect 2016 to continue the relatively high level of activity in renewables M&A. 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 2016 will likely be driven by the intense financial stress that many oil and gas companies are under. There have been expectations for some time of a distress driven wave of M&A in the sector. Perhaps 2016 will be the year it comes about.

The discussion below covers the following areas:

. Regulated Utilities

. Power Companies and Generation Assets

. Renewables

. Master Limited Partnerships

. LNG Developments

. Project Finance

. Bankruptcy Developments in the Energy Sector

Page 3

. Environmental Regulation

. FERC

. ERCOT

. CFTC

. Mexico Implementation of New Wholesale Power Markets

. Distributed Generation

Regulated Utilities

As we discussed in our memorandum last year, 2015 began with seven pending transactions involving regulated companies. Of these, four closed during the year (Integrys/WEC, AES/Ipalco/Caisse de dépôt et placement du Québec, PPL’s spin-off of Talen and NiSource’s spin-off of CPG), but three are still pending (Pepco/Exelon, Cleco/Macquarie/BCIMC, and HEI/NextEra). The Integrys/WEC transaction did face some opposition from regulators and intervenors, particularly in Wisconsin and Illinois. In Illinois, the gas main replacement program of Integrys’ Peoples Energy Subsidiary was the subject of significant controversy during the Illinois proceeding. Ultimately, however, the companies were able to satisfy regulators that they should approve the deal, and were able to complete the transaction almost a year to the day after announcement. The PPL/Riverstone/Talen spin-off also faced a significant regulatory hurdle at FERC, which mandated divestiture of 1300 MW of generation as a condition of approving the deal. The details regarding FERC’s order were detailed in our memorandum last year so we won’t repeat them here. The transaction was completed on June 1, 2015 without having to agree to significant additional conditions, resulting in the various divestitures described later in this memorandum. Finally, the NiSource/CPG spin-off was completed on July 1, 2015 without significant difficulty. In contrast to those that closed, the three transactions pending since 2014 have all encountered unusual regulatory hurdles.

Pepco/Exelon

Exelon Corporation and Pepco Holdings announced their proposed combination in April of 2014. Approvals required for the transaction include Pepco stockholders, Hart-Scott 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

Page 4

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.

Not surprisingly, 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 in the District. Following the settlement, the Mayor, the DC Council and numerous others have come out in public support of the transaction. Opponents of the transaction also waded in, causing the Commission to reopen the record in the proceeding so that it can consider additional evidence regarding the settlement agreement. Briefing ended in December and the matter is now pending before the DCPSC. The Maryland Attorney General also made an effort to have the Maryland PSC’s approval of the transaction vacated, so far without success.

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 ring- fencing commitments intended to insulate Cleco Power from its parent companies and affiliates, confirmed that Cleco Power President Darren Olagues is expected to become president and CEO of Cleco and committed that the company’s headquarters will remain in Pineville, Louisiana following completion of the transaction. The parties also indicated that Cleco will continue to operate as an independent company led by local management, and that no changes will 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 in July and without significant conditions, the Louisiana PSC decision appears to have taken longer than the parties expected. 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 this year. The cumulative additional enhancements include a $125 million rate credit, a series of financial undertakings designed to preserve Cleco Power’s investment grade credit rating and protections for employees. The parties are hoping to close during the first quarter of 2016.

Page 5

NextEra/Hawaiian Electric

Another transaction that has been delayed by the regulatory process is the NextEra/HEI transaction. The companies initially announced the $4.3 billion transaction on December 3, 2014. It requires 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 approval has taken more time.

The initial application with the HPUC was filed on January 29, 2015 and included commitments that Hawaiian Electric will not submit any applications seeking a general base rate increase and will forego recovery of the incremental operations and maintenance revenue adjustment under its decoupling rate mechanism for at least the first four years following deal closing. The companies assert that these undertakings will 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 may arise from the acquisition, and that there will be no “involuntary reductions” to Hawaiian Electric’s workforce as a result of the transaction for at least two years after deal closes. NextEra also proposed a series of ring-fencing provisions designed to ensure that Hawaiian Electric and its customers are not impacted by the activities and businesses of NextEra’s other activities.

Since the initial filing, the proceeding appears to have become bogged down in a debate over what Hawaii’s energy policy should be over the next couple decades. On the day before the companies filed their application for approval, the Hawaii Senate leader introduced a bill that would require Hawaii to get 100% of its power from renewable energy sources by 2040. The measure was subsequently enacted by the legislature with an almost unanimous vote. Hawaii already has deeper penetration of renewable energy from distributed generation than any other state.

The companies have advocated that the transaction be approved on the basis that the combination will 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 persists. The consumer advocate attempted to slow the proceedings down, but the effort was rejected by the PUC. Various political groups on the islands reportedly are considering ways to convert Maui Electric Co. and other HEI utility subsidiaries into government-owned public utilities. The Governor also has come out against the combination. The companies have vowed to press on despite the opposition, citing the potential for $1 billion in merger-related savings, boosting their proposed commitments to customers and emphasizing that the company will continue to be locally managed following the merger. The companies are now hoping to close sometime before the middle of 2016.

Iberdrola USA/UIL Holdings

The first major transaction of 2015 to be announced was Iberdrola USA’s acquisition of UIL Holdings Corporation for $3.1 billion in cash and stock, which was unveiled on February 25,

Page 6

2015. The UIL shareholders were to receive a total of 18.5% of the common equity of the combined company plus $10.50 per share in cash for each of their UIL shares. The structure was innovative in that Iberdrola USA effectively made an initial public offering of its common equity as part of the transaction. Among other things, this may provide the company with currency for future acquisitions. Iberdrola (USA) had been rumored to be looking for an acquisition for some time, reportedly having been involved in negotiations to acquire Cleco and EFH subsidiary Oncor.

In their press release announcing the transaction, the companies indicated that the proposed transaction implied total value per share to UIL shareholders of $52.75, including the $10.50 per share in cash, representing a 24.6% premium to UIL’s closing share price on February 25, 2015, and a 19.3% premium to the average closing price over the 30 days prior to announcement. The value of the stock consideration received was based on the mid-point of the combined company’s estimated 2016 and 2017 earnings per share valued at peer P/E multiples of 17.5x and 16.5x, respectively. UIL’s current President and Chief Executive Officer, James P. Torgerson, will become the company’s CEO upon closing.

The transaction was subject to approval by UIL shareholders and the public utility commissions in Connecticut and Massachusetts. At the time of announcement, the companies indicated that they were hoping to close by the end of 2015. Despite what may have been a slower than expected regulatory process, they managed to meet that goal. Filings were made in Connecticut and Massachusetts on March 25. Things were moving along quickly at first, with hearings scheduled within a few weeks after the filings, and FERC approval being granted on June 2. Then at the end of June, the Connecticut Public Utilities Regulatory Authority (PURA) issued a draft decision saying that it planned to deny approval of the transaction. Key reasons cited by the PURA for its recommendation were concerns about whether the utility would be locally managed following the merger, a lack of concrete benefits for customers and the absence of any studies regarding potential savings that would result from the merger. The regulator also wanted more information about the potential benefits and harm that could result from the merger as well as stronger ring-fencing provisions.

Shortly after the draft decision came out, the companies withdrew their application, refiling a few weeks later. The revised proposal included enhanced benefits for customers, including a rate credit of approximately $20 million. In September, the companies reached a settlement with the Connecticut consumer counsel, and then in October settled with the Massachusetts attorney general and the Massachusetts Department of Energy Resources. By this time things were back on track; the transaction closed in mid-December after receiving shareholder approval and authorization from Connecticut and Massachusetts regulators. The new company is called AVANGRID.

SourceGas/Black Hills

After the Iberdrola/UIL transaction, there was a lull in activity until July 12, 2015, when Black Hills Corporation announced the acquisition of SourceGas Holdings for $1.89 billion, including reimbursement of approximately $200 million in capital expenditures through closing and the

Page 7

assumption of $720 million in outstanding debt. The acquisition was supported by a committed bridge financing with the expectation that in addition to the issuance of 5.5 million shares of common stock, Black Hills will issue $450 million to $550 million of additional debt and $250 million of equity linked securities as part of the permanent financing. SourceGas operates four regulated natural gas utilities, serving customers in Arkansas, Colorado, Nebraska and Wyoming. The transaction required the approval of regulatory authorities in Arkansas, Colorado, Nebraska and Wyoming, as well as Hart-Scott-Rodino clearance, with Hart-Scot- Rodino clearance being obtained on August 18, 2015.

In Colorado, a settlement was negotiated with the staff of the Colorado Public Utilities Commission (CPUC), with the CPUC approving the transaction on November 17, 2015. Pursuant to the settlement, Black Hills agreed to a three year moratorium on filing rate cases and a $200,000 rate reduction. Black Hills also agreed not to seek recovery of transaction costs.

In Arkansas, the transaction was approved by the Arkansas Public Service Commission (APSC) on January 15, 2016 pursuant to a settlement negotiated with the APSC staff. Under the settlement, SourceGas Arkansas agreed to not file a rate case for 12 months following closing, and also agreed to an annual rate reduction of $250,000 that would remain in effect for 5 years or until new base rates were established, whichever is earliest. Black Hills also agreed to forego recovery of transaction costs and any acquisition premium, and also agreed that SourceGas Arkansas would not make dividend payments that would result in its stand-alone equity level falling below 40% of its long-term capitalization.

The Nebraska Office of the Public Advocate (OPA) opposed the transaction as initially structured, but the parties reached a negotiated settlement that was approved by the Nebraska Public Service Commission (NPSC) on January 26, 2016. Pursuant to the approval, SourceGas, which will be re-branded Black Hills Gas Distribution (BHGD), agreed to a 3 year rate freeze following closing, while the OPA agreed to not seek any reduction in BHGD’s rates for 5 years after closing or until BHGD files another rate case, whichever occurs first. Various ring fencing provisions were also implemented, and if BHGD issues new debt, it is prohibited from making dividend payments that would result in its stand-alone equity level falling below 40% of its long- term capitalization, unless authorized by the PSC. Black Hills was also prohibited from recovering any transaction costs or shareholder litigation costs.

The transaction closed on February 12, 2016.

EFH/Hunt Consolidated/Oncor

Energy Future Holdings announced on August 10, 2015 that it had agreed to transfer its 80% ownership interest in Oncor Electric Delivery Company to Hunt Consolidated as part of a broader plan to emerge from bankruptcy. The announcement followed a lengthy, sometimes contentious bidding process for Oncor. The transaction was valued at $18.9 billion. The transaction is subject to approval by the bankruptcy court, the Public Utility Commission of Texas (PUCT) and other regulatory agencies. The investor group includes Hunt Consolidated, new investors, and current creditors of EFH and its subsidiaries, who are investing more than $7 billion of additional equity as part of the transaction.

Page 8

Another interesting element of the transaction is that it involves restructuring Oncor as a REIT. Under the REIT structure, the assets and liabilities historically owned and operated by Oncor will be divided between two separate entities. Oncor AssetCo will directly or indirectly own the transmission and distribution assets that are treated as real property for U.S. federal income tax purposes. A newly formed entity, Oncor Electric Delivery Company LLC (OEDC), will own certain personal property and various other assets. Oncor AssetCo will lease substantially all of its transmission and distribution assets to OEDC.

Since the announcement, the bankruptcy court approved the transaction and confirmed EFH’s plan of reorganization. FERC has also provided necessary approvals. The transaction is currently under review by the PUCT, which is expected to rule late next month. Timing for the closing of this transaction will depend on the outcome of the PUCT proceedings, as well other regulatory approvals, including the Nuclear Regulatory Commission.

AGL Resources Inc./Southern Company

Later in August, Southern Company announced that it would acquire AGL Resources in a $12 billion transaction. AGL shareholders will receive $66 in cash per share for their stock, representing a premium of 36.3% to the volume-weighted average stock price of AGL Resources for the 20 trading days prior the announcement. The merger would create 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 represents a step in new strategic direction for Southern and was well received by analysts and stockholders. Southern said it plans to fund the deal through debt and equity, with roughly $3 billion in equity issuances spaced out through 2019. After closing, AGL Resources will retain its own 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 FTC approval, the transaction requires approval from regulators in five states - Georgia, Illinois, Maryland, New Jersey and Virginia. Applications in each state have been filed and are pending. Shareholders approved the transaction on November 19 and HSR clearance was received on December 4. The companies currently estimate that the transaction will close during the second half of 2016.

TECO Energy, Inc./Emera Incorporated

The AGL/Southern transaction was followed less than two weeks later by TECO Energy’s announcement 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 will receive $27.55 per share in cash, a 48% premium to the unaffected closing share price of July 15, which was the day after TECO disclosed that it was exploring strategic alternatives for the company. The combined company will have more than $20 billion in assets and more than 2.4 million electric and gas customers.

Page 9

For Emera, the transaction represents the culmination of a long search for an opportunity to expand; management expects the transaction to give the company additional geographic, regulatory and business diversification. The deal would expand Emera’s geographic platform into Florida and New Mexico, 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. Upon completion, 56% of Emera’s asset base will be in Florida, with 23% in Canada, 10% in New England, 6% in New Mexico and 3% in the Caribbean, where Emera has holdings in electric utilities serving several island nations.

Shortly after announcement, Emera entered into an interesting 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 the closing of the TECO acquisition. Prior to the final installment date, the debentures will be represented by installment receipts and will be listed and posted for trading on the Toronto Stock exchange. This financing fully addresses Emera’s common equity financing needs for the acquisition.

Closing is subject to TECO shareholder approval, approval by the New Mexico Public Regulation Commission and FERC, Hart-Scott-Rodino clearance and clearance by the Committee on Foreign Investment in the United States. Shareholder approval was obtained on December 3, FERC granted its approval on January 21, 2016 and the Hart-Scott-Rodino waiting period expired on February 8, 2016. The companies expect closing to occur by mid-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 net debt. Piedmont shareholders will receive $60 per share for their equity, an extraordinary 40% premium to the closing price on the trading day prior to announcement. 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 include approval by the North Carolina Utilities Commission, Hart- Scott-Rodino clearance and Piedmont shareholder approval. The companies also indicated that they will provide information regarding the acquisition to the Public Service Commission of South Carolina and the Tennessee Regulatory Authority. So far, the companies have received FTC approval and have filed applications for approval with the North Carolina Utilities Commission and the Tennessee Regulatory Authority. Closing is expected sometime in the second half of 2016.

Questar/Dominion

Mergers continued into 2016 with Questar Corp. and Dominion Resources Inc. announcing on February 1, 2016 that Dominion will acquire Questar for approximately $6 billion, including

Page 10

assumption of $1.6 billion of debt. The primary drivers of this transaction appear to be an opportunity for Questar to contribute its pipeline assets to an MLP (Dominion Midstream) even though it does not have the scale to establish its own MLP as well as potential geographic 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.

ITC Holdings/Fortis Inc.

On February 9, 2016, Fortis Inc. and ITC Holdings Corp. announced an agreement pursuant to which Fortis will acquire ITC for approximately $7 billion. Under the terms of the transaction ITC shareholders will receive $22.57 in cash and 0.7520 Fortis shares per ITC share. Fortis will also assume approximately $4.4 billion of consolidated ITC indebtedness. The financing of the cash portion will be achieved through the issuance of approximately $2 billion of Fortis debt and the sale of up to 19.9% of ITC to one or more infrastructure-focused minority investors. Upon completion of the acquisition, ITC will become a subsidiary of Fortis and approximately 27% of the common shares of Fortis will be held by ITC shareholders. Fortis will apply to list its common shares on the New York Stock Exchange in connection with the acquisition and will continue to have its shares listed on the Toronto Stock Exchange. The transaction is subject to HSR and CFIUS clearance as well as approval from FERC and state regulators in Illinois, Kansas, Missouri, Oklahoma and Wisconsin. The companies do not expect to be required to seek state approvals in Iowa, Michigan or Minnesota. Fortis President and CEO Barry Perry also noted that FERC is the only jurisdiction with regulation over ITC's transmission rates.

The Empire District Electric Company/Algonquin Power and Utilities Corp.

Also on February 9, 2016, Liberty Utilities (Central) Co., a subsidiary of Algonquin Power & Utilities Corp. entered into an agreement to acquire The Empire District Electric Company for $2.4 billion in cash. Under the terms of the agreement, $34 will be paid as consideration for each share of Empire District stock, 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 is expected to be obtained by placements of common equity, preferred equity, convertible debentures and long term debt, along with the assumption of existing Empire indebtedness. The management team of Empire District will lead Liberty Utilities’ Central US Region and Algonquin expects to retain all Empire District employees, as a result of which no changes to management or employee staffing at Empire are expected as a result of the transaction.

The transaction is subject to approval of Empire shareholders, state regulatory commissions in Arkansas, Kansas, Missouri and Oklahoma, the FCC, CFIUS and FERC, and HSR clearance.

Power Companies and Generation Assets

The unregulated side of the electric industry saw a decline in M&A activity, with $8.1 billion in thermal electric generation transactions, down from $12.3 billion in 2014, and $9.8 billion in 2013. The value of transactions involving renewable generation assets increased from $7.5 billion to $8.5 billion. Much of the activity focused on renewables portfolio transactions, some

Page 11

of which are described in more detail in the next section. YieldCos continued to be active in 2015, particularly in acquiring contracted wind and solar assets. Strategic buyers outnumbered private equity and financial investors by a fairly large margin.

NextEra/EFH

In an interesting turn of events, one of the biggest acquisitions for electric generating assets this year was done by debtor Energy Future Holdings (EFH). EFH agreed to purchase the Forney Energy Center and Lamar Energy Centers in ERCOT from NextEra Resources for approximately $1.59 billion. EFH filed for Chapter 11 protection on April 29, 2014. NextEra competed with Hunt Consolidated and others to be the stalking horse bidder for Oncor, which is a regulated subsidiary of EFH. The EFH/Hunt transaction is described in more detail above. EFH, even in bankruptcy, had been shopping for electric generation assets in ERCOT, being an unsuccessful bidder in the bankruptcy auction of debtor Optim Energy for the Twin Oaks lignite-fired generation facility in 2014. EFH then prevailed in the NextEra auction for the Forney and Lamar facilities. EFH received bankruptcy court and creditor approval for this acquisition. The transaction remains subject to other closing conditions, and the parties have announced they expect to close in the spring of 2016.

Talen Divestitures

As part of satisfying FERC market power concerns arising from the combination of PPL and Riverstone assets to form Talen, Talen announced several electric generation asset sales in 2015. Talen agreed to sell its 704 MW Ironwood plant to TransCanada for $654 million, with the sale closing on February 2, 2016. Talen also announced the sale of its Holtwood and Lake Wallenpaupack hydroelectric projects, with a combined generating capacity of approximately 292 MW, to a subsidiary of Brookfield Renewable Energy Partners L.P. for $860 million. In addition, Talen entered into an agreement with Avenue Capital to sell the CP Crane coal-fired generation facility in Baltimore. Consummation of the CP Crane sale will not only assist mitigating FERC’s market power concerns, but also limit Talen’s potential liabilities with the older coal-fired CP Crane facility. Both the CP Crane and hydro sales are expected to close in early 2016.

Tenaska/ArcLight

In one of the largest portfolio transactions of the year involving private equity, a subsidiary of ArcLight, Eastern Generation, agreed to purchase approximately 5,000 MW of electric generation from Tenaska in October 2015. The portfolio included the Astoria Generating, Narrows and Gowanus generating facilities in New York, the Crete and Lincoln generating facilities in Illinois (which ArcLight and DTE sold to Tenaska in 2007), the Covert generating facility in Michigan and the Rolling Hills generating facility in Ohio. After receiving FERC and NYPSC approval and satisfying other closing conditions, the transaction closed on December 23, 2015.

Calpine/Granite Ridge

Page 12

In October 2015, Calpine announced that it had agreed to acquire the Granite Ridge Energy Center, which is an approximately 745 MW combined cycle gas-fired power plant in Londonderry, New Hampshire, from Granite Ridge Holdings for $500 million. As one reason for the transaction, Calpine cited improving capacity prices in New England over the next three years. The transaction was subject to customary regulatory approvals and the approval of the New Hampshire Site Evaluation Committee, all of which were obtained in due course, and the transaction proceeded to closing on February 5, 2016.

Duke/NCEMPA

As reported last year, Duke Energy Progress (Duke Progress) and North Carolina Eastern Municipal Power Agency (NCEMPA) entered into an agreement for Duke Progress to purchase NCEMPA’s ownership interest in five generating assets located in North Carolina, consisting of interests in three nuclear units and two coal fired units, for $1.278 billion.

On April 2, 2015, North Carolina enacted a bill authorizing Duke Progress to recover the costs of the acquisition in rates, on a levelized cost basis. The transaction closed in July 2015.

Union Power/Entergy

Also as reported last year, Entergy entered an agreement to buy from Entegra Power Group the more than 2,000 MW Union power station near El Dorado, Arkansas for $948 million. In the transaction, Entergy subsidiaries Entergy Arkansas Inc. and Entergy Texas Inc. each originally planned to acquire one unit at the four-unit plant. Entergy Gulf States Louisiana LLC will acquire the other two units and plans to sell 20% of the output to Entergy New Orleans Inc. In September 2015, Entergy Texas filed a motion to withdraw its request for approval from the PUCT with respect to the purchase of the El Dorado plant. If granted, Entergy New Orleans would end up acquiring the El Dorado plant instead of Entergy Texas, and the power purchase between Entergy Gulf States Louisiana and Entergy New Orleans would no longer take place.

The acquisition is pending approvals for cost recovery from regulators, including approval by the New Orleans City Council, according to a statement from Entergy.

Renewables

Renewables M&A Activity

2015 saw a continuation of the high level of M&A activity in the renewables space that developed in 2014. YieldCo related transactions remained a significant driver of this activity, but as the year progressed and YieldCos encountered various headwinds, institutional and private equity investors stepped in. Announced deals for 2015 totaled approximately $8.5 billion, compared to approximately $7.5 billion in 2015 and $2.5 billion in 2013. Transactions involving SunEdison/TerraForm accounted for approximately $4.7 billion of the total, while Southern Power Company accounted for $1.0 billion. Notes on selected transactions follow:

Page 13

Terraform Power/Invenergy

On July 6, 2015, TerraForm Power Inc., the SunEdison affiliated YieldCo, announced the acquisition of a portfolio of wind farms totaling approximately 930 MW from a consortium led by Invenergy. The aggregate purchase price was $2.0 billion, with just over $1.0 billion for projects that will be put into TerraForm immediately, while the remainder, purchased for approximately $995 million, will be housed in a warehouse facility sponsored by SunEdison and third-party equity investors. Invenergy will be retaining a 10% interest in, and continue as the operations and maintenance manager of, the U.S. based projects (California Ridge, Bishop Hill, Prairie Breeze and Rattlesnake),while the consortium sold 100% of the interests in the one Canadian project included in the transaction (Raleigh). On December 16, 2015, the parties proceeded to closing with respect to 832 MW of the portfolio, with the remaining 98 MW expected to close in early 2016.

SunEdison/Vivint

On July 20, 2015, SunEdison announced the acquisition of Vivint Solar in a cash and stock deal initially valued at $2.2 billion. The transaction was to be SunEdison’s first foray into the rooftop solar business, but it has not gone smoothly. The ensuing drama at SunEdison has been covered extensively in the press, so we will not go into detail here. Suffice it to say that at the end of the year the Vivint transaction remains pending, having been restructured to lower the price to approximately $1.8 billion. Closing is expected in the first quarter of 2016.

Southern/Recurrent, Southern/First Solar and Southern/Apex

The third quarter saw a flurry of activity by Southern Company in the renewables space, on top of its acquisition of AGL.

On August 28, 2015, Southern Company subsidiary Southern Power Company announced that it had closed on the acquisition of a 51% interest in the Tranquillity solar facility from Recurrent Energy for a purchase price of $100 million. The project, located in Fresno County, California, has a 15 year power purchase agreement with Southern California Energy and is expected to go into commercial operation in the fourth quarter of 2016.

On September 2, 2015, Southern Power announced that it had closed on the acquisition of a 51% interest in the 300 MW Desert Stateline solar project from First Solar. First Solar will retain the remaining stake in the project, which is expected to be fully operational by the third quarter of 2016. The project has a 20 year power purchase agreement with Southern California Edison.

On September 4, 2015, Southern Power entered into an agreement for the acquisition of Grant Wind, an approximately 150 MW wind farm in Grant County, Oklahoma, from Apex Clean Energy Holdings for a purchase price of approximately $264 million. Southern filed for FERC approval on the same date, which is still pending. The acquisition is subject to Apex achieving certain construction and project milestones, and is expected to close at or near the commercial operations date, which is expected in the first quarter of 2016.

Page 14

Brookfield/Talen

On October 8, 2015, Brookfield Renewable Energy Partners announced the acquisition from Talen Energy of two hydroelectric projects for a purchase price of $860 million. The two facilities are the Holtwood and Lake Wallenpaupack facilities, with a combined generating capacity of 292 MW. In its December 2014 order approving the formation of Talen, FERC required Talen to divest certain assets, with the Holtwood and Lake Wallenpaupack facilities being included as possible targets. Talen filed for FERC approval of the transaction on November 10, 2015.

Regulatory Developments

On December 18, 2015, extensions to the production and investment tax credits that are applicable to wind, solar and other renewable power projects were enacted pursuant to an omnibus spending bill passed by Congress. The legislation 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 changes in the methodology for qualifying. The legislation also extended “bonus depreciation” through 2019.

PTC. As regards the PTC, any wind facility that commences construction prior to January 1, 2020 can qualify for the 10 year credit, subject, however, to a phased reduction in the amount of the available credit.

. Wind facilities that commence construction prior to January 1, 2017 will qualify for the full amount of the PTC.

. For wind facilities that commence construction during 2017, the amount of the PTC will be reduced by 20%.

. For wind facilities that commence construction during 2018, the amount of the PTC will be reduced by 40%.

. For wind facilities that commence construction during 2019, the amount of the PTC will be reduced by 60%.

For any wind facility claiming the ITC in lieu of the PTC, the available ITC is subject to a similar step-down.

ITC. The ITC available for commercial solar facilities had been set to step down from 30% to its permanent level of 10% for any solar projects placed into service on or after January 1, 2017. Under the legislation, the ITC is now subject to a phased step down commencing January 1, 2020, with the drop to 10% now slated for January 1, 2022. In addition, the legislation changes the eligibility deadline from a placed in service requirement to a commencement of construction requirement (but subject to being placed into service by January 1, 2024). Specifically, the Act provides as follows:

Page 15

. Solar facilities that commence construction prior to January 1, 2020 will qualify for the full amount of the ITC (i.e., 30%).

. For solar facilities that commence construction during 2020, the amount of the ITC will be reduced from 30% to 26%.

. For solar facilities that commence construction during 2021, the amount of the ITC will be reduced from 26% to 22%.

. For solar facilities that commence construction in 2022 or thereafter, the amount of the ITC will drop to 10%.

. The legislation also establishes a placed in service deadline such that for solar facilities that commence construction any time prior to January 1, 2022 but which are not placed into service before January 1, 2024, the amount of the ITC will be reduced to 10%.

The legislation also extended the ITC available to residential solar facilities (e.g., rooftop solar and solar water heaters), again subject to a phase out and in this case continuing the placed in service requirement for eligibility (as opposed to making the change to the commencement of construction test). Specifically:

. For residential solar projects that are placed into service prior to January 1, 2020, the amount of the ITC is 30%.

. For residential solar projects that are placed into service prior to January 1, 2021, the amount of the ITC will be reduced from 30% to 26%.

. For residential solar projects that are placed into service prior to January 1, 2022, the amount of the ITC will be reduced from 26% to 22%.

. There is no ITC available for residential solar projects after December 31, 2021.

The ITC available to all other residential energy efficiency property (i.e., for qualified fuel cells, small wind energy and geothermal heat pump property) remains unchanged, and thus continues at 30% but expires on December 31, 2016.

Bonus Depreciation. The legislation extends “bonus depreciation” for property acquired and placed in service before 2020. The bonus depreciation percentage will be 50% for property placed in service before 2018. However, the percentage decreases in subsequent years to 40% in 2018 and 30% in 2019.

Companies that place equipment in service before 2020 can therefore deduct the applicable bonus percentage of the tax basis in the equipment immediately and the remaining basis using the normal depreciation table (e.g., over 5 years in the case of wind and solar facilities and other eligible renewable energy property, or over 3 years for similar property located on qualified Indian reservation property if placed into service before 2017).

Page 16

Bonus depreciation is extended under the legislation for an additional year (i.e., for property acquired and placed in service before 2021) for certain property with an estimated production period of greater than one year and costing more than $1 million, provided the property’s recovery period is at least 10 years (e.g., gas and electric transmission property) or the property is “transportation property” (e.g., airplanes).

Renewables Development Activity

Wind. On the development side of the equation, 2015 was a strong year for wind installations, with 8,598 MW installed as compared to 4,854 MW in 2014, which was in turn a significant increase from the 1,087 MW installed in all of 2013. With the long-term extension of the PTC providing regulatory certainty, expectations for an even stronger 2016 are high, with the American Wind Energy Association reporting over 9,400 MW under construction.

Solar. Meanwhile, solar power installations continued their strong development activity, with the Solar Energy Industries Association reporting that through the third quarter of 2015 4,110 MW of PV solar was installed, with a record-breaker 3,000 MW expected to come online in the fourth quarter alone. This compares with 6,201 MW of PV solar was installed in 2014, a strong year in its own right. The long-term extension of the ITC described above is expected to only further encourage solar installations in 2016, which was already forecast to be a record year for the industry.

Master Limited Partnerships (MLPs) and YieldCos

MLP Capital Markets in 2015

During the first half of 2015, lower but sustainable oil prices and a robust broader stock market supported MLP market performance. During the second half of 2015, a severe decline in oil prices, distribution reductions and a volatile and weak broader stock market hindered MLP market performance. Although the S&P 500 was only down 0.7% for 2015, the Alerian MLP Index declined 36.9%, with a total return of (32.6%) (compared to an 0.9% increase and total return of 4.8% in 2014). This was the fourth year in a row that the Alerian MLP Index Return did not outperform the S&P 500 Return. As usual, midstream MLPs (specifically, natural gas pipelines) and publicly traded general partners of MLPs provided the greatest total return among MLP equities. Upstream, marine transportation / offshore drilling and gathering and processing MLPs were the worst performing sectors as they were caught up in the sharp decline in commodity prices and higher risk of shorter term contracts.

In the second half of 2015, activity in the MLP capital markets pretty much slowed to a halt. There were 6 MLP IPOs for $4.9 billion of gross proceeds (as compared to 20 MLP IPOs for $7.7 billion of gross proceeds in 2014). The largest MLP IPO in history (Columbia Pipeline Partners) was completed in February 2015, but there were no MLP IPOs completed after June 30, 2015. For perspective, we have seen an average of 10 MLP IPOs over the last 10 years, 100 in total, including 74 since the beginning of 2010. In contrast to the last two years, no new MLPs entered the market with a variable pay structure (i.e., the MLP does not have a minimum quarterly distribution).

Page 17

The IRS lifted the “pause” on the issuance of private letter rulings regarding qualifying income and issued proposed regulations in May 2015 that would define exclusively which activities will derive qualifying income. Several MLPs, advisors to MLPs and industry groups provided the IRS with extensive comments on the proposed regulations and testified before the IRS regarding those comments. It is not clear when the final regulations will be issued. It is expected that MLPs whose income is no longer qualifying under the final regulations will have 10 years to transition out of the MLP tax structure.

There were two IPOs of general partners in 2015 (as compared to at least one general partner IPO in each of in 2010-2013 and none in 2014). Interestingly, EQT GP Holdings used an MLP structure and Tallgrass GP Holdings used a YieldCo structure. The Tallgrass GP IPO was the second largest IPO in the United States in 2015 and the corporate tax aspect of its YieldCo structure allowed Tallgrass GP Holdings to sell its Class A Shares to a larger number of U.S. tax- exempt investors and non-U.S. investors than a traditional MLP.

Particularly in light of market uncertainty, would-be MLPs going through the SEC’s IPO review process continued to take advantage of Emerging Growth Company status under the JOBS Act of 2012. This status, among other things, allows issuers to file the IPO registration statement confidentially until 21 days before the launch of the IPO and present only two years of audited financial statements. (This 21-day public period has now been shortened to 17 days under the FAST Act.) As a result, sponsors were able to put the MLP IPO process on hold without public notice.

During 2015, there were 36 follow-on equity offerings by existing MLPs generating $9.1 billion in gross proceeds (as compared to 61 transactions generating $19.1 billion in gross proceeds in 2014). Only 10 of these transactions took place in the second half of 2015. Bought deals and confidential marketed offerings (CMPOs) became more popular as the markets became more volatile. Bought deals provide greater certainty to the issuer as to 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 2015, there were 10 private placements to third parties or affiliates for $3.0 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.

In addition, the tighter makers 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 the convertible preferred units issued by EnLink to a private equity firm. The convertible preferred units provide the holders with an annual PIK 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. (There were two more offerings of convertible preferred units in January 2016.)

Page 18

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.

Institutional investor participation in MLP IPOs continued to grow, with institutions often purchasing more than half of the public equity in IPOs and anchoring the few follow-on equity offerings that did get done. This increasing access to institutional buyers supports larger securities offerings and contributes to less volatility in MLP equity, although overall institutional ownership of MLPs remains at a level below that of other yield stocks.

The debt capital markets were open to MLPs in the first half of 2015 but largely closed in the second half of the year. MLPs engaged in 29 bond offerings for $34.1 billion in gross proceeds (as compared to a record 59 bond offerings for $37.8 billion in gross proceeds in 2014).

2015 was 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 services MLPs reducing or suspending their quarterly distributions (a continuation of the five reductions in 2014).

MLP M&A in 2015

In 2015, the heightened level of M&A activity that had been anticipated in late 2014 as oil prices fell did not materialize and M&A activity levels remained generally consistent with healthy levels. The volume of M&A transactions in the MLP sector reached 94 transactions for total disclosed value of $133.3 billion (as compared to 109 transactions for total disclosed value of $130.8 billion in 2014). MLP consolidation continued in the upstream and midstream sectors with 11 transactions. MLP buybacks and general partner sales also continued as sponsors came under financial or market pressure. However, despite the challenges of the overall market, 2015 was a record year for public MLP M&A with eight transactions for $96.0 billion. To put this into context, in 2013 and 2014, six and seven public MLP transactions were completed for $19.4 billion and 101.3 billion, respectively.

The largest MLP M&A transaction announced in 2015 was Energy Transfer Partners’ pending $37.7 billion acquisition of Williams Companies (which owns Williams Partners), followed by MPLX’s $19.7 billion completed acquisition of MarkWest Energy Partners. Other notable transactions included Energy Transfer Partners’ $18.0 billion acquisition of its MLP Regency Energy Partners, Targa Resources Corp.’s acquisition of its MLP Targa Resources Partners, and corporation Murray Energy’s acquisition of a controlling stake in competitor MLP Foresight Energy. The ETP/WMB deal, the MPLX/MWE deal and the ETP/RGP deal comprised the three largest M&A transactions in the energy sector in 2015. It is worth noting that some of the consolidation involved higher yielding midstream MLPs being acquired by lower yielding MLPs or companies (such as MPLX/MWE, TRGP/NGLS and CEQP/CMLP), and we may see more of this opportunistic M&A activity in the next year as even the midstream MLPs feel the pressure of lower oil prices and higher yields.

Page 19

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 entities. However, as MLPs played it safe and steady in the volatile market, 2015 did not include dropdowns with 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, such as TC PipeLine’s tracking stock and Shell Midstream’s PIPE.

YieldCo Capital Markets in 2015

There were two YieldCo IPOs in 2015 (as compared to three in each of 2014 and 2013), 8point3 Energy and TerraForm Global. 8point3 Energy is a joint venture between First Solar and SunPower. TerraForm Global is SunEdison’s second YieldCo, focusing on international solar development. Much like MLPs, YieldCos suffered in the marketplace in the second half of 2015. From late May through late August, YieldCo shares fell by over 50% from their market peak, which produced widespread investor concern over the function, transparency and durability of YieldCos. Interestingly, for YieldCos whose sponsors failed to meet second quarter earnings expectations (such as ABY, NYLD/NRG and TERP/SUNE), the average return was much lower. YieldCos whose sponsors met expectations and YieldCo performance and sponsor performance had correlations above 90%.

YieldCo M&A in 2015

With two exceptions, M&A among YieldCos was relatively quiet in 2015. The most interesting transaction involved a YieldCo’s acquiring midstream assets that would typically be held by an MLP. In July, NextEra Energy Partners acquired NET Midstream from its sponsor for $2.1 billion. The acquisition was financed with a public equity offering that priced 8% below the closing market price per share. Also in July, SunEdison and its domestic YieldCo TerraForm Power announced an agreement to acquire Vivint Solar for $2.2 billion, capping two months in which TerraForm Power had acquired over $3.5 billion in assets. However, in October, following downward revisions in earnings guidance by another YieldCo and credit rating agencies issuing negative watches on other YieldCos, SunEdison announced it would no longer dropdown assets into TerraForm Power and TerraForm Global until the market dislocation ends. As noted above, the Vivint transaction also has been restructured.

To use a phrase with which the energy industry is familiar, 2016 is a “hunker down and ride it out” year for MLPs and YieldCos.

LNG Developments

In 2015, 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. Regulatory developments in 2015 primarily dealt with clarification of the jurisdiction of FERC and the DOE/FE over LNG projects and the export of LNG, providing more regulatory certainty for project proponents. These developments, along with several potential legal challenges brought by various environmental and industry groups to FERC and

Page 20

DOE/FE authorization of several LNG projects, are likely to shape the legal and regulatory developments for the LNG industry in 2016.

Federal authority over LNG export activities is divided between the DOE/FE and FERC, with the DOE/FE charged with reviewing applications to export natural gas commodities and FERC responsible 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 the 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 the DOE/FE several months to process an application to export to an FTA Country whereas it can take several years for the DOE/FE to process an application for exports to a Non-FTA Country.

In 2015, the Obama administration announced that it had concluded negotiations of the Trans- Pacific Partnership Agreement (TPP), a landmark free trade agreement among the United States and 11 other Pacific nations. Notably, if the TPP is ratified, the signatory countries will be treated as FTA Countries for the purpose of the DOE/FE’s review and approval process. As such, the DOE/FE will be required to promptly approve applications for authorization to export LNG from the U.S. to the other TPP countries, including Vietnam and the world’s largest LNG importer, Japan.

As of December, 2015, 28 applications to export LNG to Non-FTA Countries, totaling 29.33 Bcf/d, remain pending before the DOE/FE. Pursuant to a new policy adopted in 2014 the DOE/FE no longer issues conditional authorizations for exports from the lower-48 states to Non- FTA Countries. Instead, for LNG projects subject to FERC’s jurisdiction, the DOE/FE will wait to issue an export authorization until FERC has completed, and the DOE/FE has reviewed, the NEPA analysis prepared for the associated LNG terminal project. In 2015, the DOE/FE issued final authorizations to Dominion Cove Point LNG, Sabine Pass Liquefaction and Corpus Christi Liquefaction to export LNG, totaling up to 4.25 Bcf/d, to Non-FTA Countries after FERC completed its NEPA analysis of those projects. Additionally, the DOE denied requests for rehearing of two orders it issued in 2014 approving LNG exports from the Cameron LNG and Freeport LNG terminals, allowing environmental and other groups to challenge the agency’s decisions in federal court. The DOE/FE also issued a conditional export authorization in 2015 to Alaska LNG, which, being outside the lower 48, is not subject to the same limitation on conditional authorizations.

The DOE/FE also issued several orders that clarified how it would process applications for exports to Non-FTA Countries where the liquefaction facility is not subject to FERC jurisdiction. Under DOE/FE regulations, natural gas export activities requiring only minor operational

Page 21

changes to existing projects, but no new construction, do not require the preparation of an environmental impact statement or environmental assessment under NEPA. In 2015, the DOE/FE found that a non-FERC jurisdictional liquefaction facility that was in the advanced stages of construction and being built to serve domestic demand to be categorically exempt from the NEPA requirements because the facility would be constructed regardless of DOE/FE action on the export application. Being categorically excluded from NEPA review can expedite the DOE/FE review of applications to export to Non-FTA Countries. In 2015, in Emera CNG, the DOE/FE, together with the National Energy Technology Laboratory, conducted its first NEPA review for a natural gas export project that was not FERC jurisdictional, but not categorically exempt from NEPA review. With FERC’s disclaimer of jurisdiction over more liquefaction projects (discussed below), the DOE/FE’s NEPA review for Emera CNG is instructive for other non-FERC-jurisdictional project proponents.

The DOE/FE also clarified in 2015 what type of authorization would be required if natural gas were exported to an FTA Country, liquefied, and re-exported to a Non-FTA Country. In Pieridae Energy (USA), Ltd. the DOE/FE concluded that in determining whether an export is to an FTA Country or Non-FTA Country, the DOE/FE will consider the trade status of the country to which the LNG is delivered for “end use,” which it defined as “combustion or other chemical reaction conversion process (e.g., conversion to methanol).” Pieridae and subsequent orders effectively eliminated the possibility of obtaining the expedited review provided for exports to FTA Countries for those projects that were exporting to an FTA Country for re-export to Non-FTA Countries.

Although Pieridae has clarified the type of authorization that is required for exports for re- export, the DOE/FE’s introduction of the “end use” standard in Pieridae and subsequent orders did not address the liability that exporters of U.S. natural gas may face if LNG destined for a specific country is diverted by downstream purchasers to another destination not authorized by the DOE/FE or is commingled with non-U.S. gas such that it cannot be determined where U.S. gas is ultimately consumed. These lingering questions about the liability of the exporter for the actions of downstream purchases and in the event of commingling create some regulatory uncertainty for project proponents.

In 2015, the DOE/FE announced the availability of two follow-on studies regarding the natural gas price impacts of LNG exports for export quantities between 12 Bcf/d and 20 Bcf/d. In 2011, the DOE/FE commissioned reports by the U.S. Energy Information Administration (EIA) and NERA Economic Consulting regarding the potential impact of proposed LNG exports on domestic natural gas prices. Among other things, the initial EIA and NERA studies looked at the impact of a “low” export case of 6 bcf/d and a “high” export case of 12 bcf/d on domestic gas prices and concluded that the effect of LNG exports on domestic natural gas prices would be modest and that net U.S. economic impacts would be positive. In 2014, pursuant to the DOE/FE’s request, the EIA conducted a further cumulative impact study as a follow up to its 2012 report on impacts associated with LNG exports from the U.S. The EIA studied the impacts of potential LNG exports in volumes between 12 and 20 Bcf/d, concluding that price impacts from increased exports would be modest and overall economic impacts would be positive. In 2015, the DOE/FE announced the availability of the second part of the updated study – a scenario-based assessment of the macroeconomic impact of levels of U.S. LNG exports sourced

Page 22

from the lower-48 states in volumes ranging from 12 to 20 Bcf/d of natural gas under a range of assumptions, including U.S. resource endowment, U.S. natural gas demand, international LNG market dynamics, and other factors. The study was performed by the Center for Energy Studies at Rice University’s Baker Institute and Oxford Economics. The study concluded that the overall macroeconomic impacts of LNG exports are “marginally positive.” The results of the follow-on studies are encouraging for LNG export project proponents, which have experienced some anxiety about past statements from the DOE/FE suggesting that the agency may use its authority to limit the overall volume of LNG it authorizes for export. To date, while the DOE/FE has emphasized that it will continue to evaluate the cumulative effects of successive export authorizations on domestic prices and other public interest factors, it has not proposed any overall volumetric limitations on LNG exports.

This past year saw more projects proposing to transport, and in some cases export, LNG in ISO containers. Thus far, most projects have proposed the transportation of the ISO containers by truck or barge. However, in 2015, the Federal Railroad Administration issued its first approval for the transportation of LNG by rail to the Alaska Railroad Corporation. Additional applications for the transport of LNG by rail are pending.

For its part, FERC approved proposals for the construction and expansion of several LNG export terminal projects in 2015, including Trunkline’s Lake Charles project and an expansion of the previously-approved export facilities of Sabine Pass LNG. FERC also denied requests for rehearing of its 2014 orders approving the Corpus Christi LNG and Dominion Cove Point LNG export projects, opening the way for opposition groups to challenge those approvals in federal court. As with similar projects FERC has approved in the past, the proceedings concluded in 2015 were 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. Opponents of the various LNG export projects have filed judicial appeals of FERC’s orders. These proceedings, which are now pending before the D.C. Circuit, could have a significant impact on future LNG export projects, as well as the larger natural gas industry, depending on how the court rules on the sufficiency of FERC’s NEPA analysis.

In addition to large LNG terminals, several minor LNG export projects have been proposed using small-scale facilities. For example, export proposals have been suggested using FERC jurisdictional and non-jurisdictional peak-shaving facilities, and certain skid-mounted modular “micro-LNG” plants, as well as ISO shipment containers. In 2015, FERC continued a trend set in 2014 of disclaiming jurisdiction over small-scale LNG facilities, providing some encouragement to this growing industry segment. Specifically, FERC issued a declaratory order to Pivotal LNG, Inc., suggesting that FERC may limit its exercise of jurisdiction over LNG export facilities to those plants that are both (i) connected to the interstate or intrastate pipeline grid and (ii) accessible to ocean-going, bulk LNG vessels.

Page 23

Throughout 2015, 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 2015 legislative session. The Obama administration has indicated that it would oppose legislation that would curtail the DOE/FE’s ability to fully consider whether natural gas export projects are consistent with the public interest.

Project Finance

On the whole, 2015 was a relatively strong year for project finance in the Americas. A few very large projects, together with significant activity in the renewables and conventional power sectors, contributed to the positive results. However, the continued slump in commodity prices and a variety of other factors created some uncertainty toward the end of the year, and early indicators suggest that terms may tighten in 2016.

Among the notable transactions consummated in 2015, two large LNG financings stand out. In April, Freeport LNG closed a $3.6 billion seven-year construction facility for the third train of its natural gas liquefaction project located on Quintana Island near Freeport, Texas, while also raising an additional $3.0 billion for refinancing and acquisition costs associated with existing facilities. The third train is backed by 20-year liquefaction tolling agreements with SK E&S LNG and Toshiba Corp. and is expected to be completed in late 2018. Then in May, Cheniere Energy closed a limited recourse financing in the amount of approximately $11.5 billion for its LNG export project located in Corpus Christi, Texas, which is designed for up to three trains with expected aggregate nominal production capacity of approximately 13.5 million tonnes per annum. In addition to its size, the Corpus Christi financing is noteworthy because it is the first greenfield LNG liquefaction project in the United States in close to 40 years. The other large LNG export projects completed in recent years were all developed on brownfield sites.

In the power sector, the wave of financings for projects incorporating merchant elements continued in 2015. Such transactions include, among others, the debt financing for Competitive Power Ventures’ 720 MW Valley Project located in Orange County, New York, the $477 million debt financing for the St. Joseph Energy Center in New Carlisle, Indiana, which is sponsored by Ares EIF Group and Toyota Tsucho Corp., the $730 million financing to fund Footprint Power’s Salem Harbor 700 MW gas-fired project in Salem, Massachusetts and the $488 million debt financing for the 700 MW Carroll County Energy project in Ohio being developed by Advanced Power with equity funding from TIAA-CREF, Chubu Electric Power Company, Ullico and Prudential Capital Group.

Another significant development in 2015 was the successful financing of the Block Island Wind project, the first utility-scale offshore wind farm in North America. The 30 MW project, which is comprised of five turbines located offshore Rhode Island, was financed in the commercial bank market with a more than $290 million non-recourse facility on the basis of 20--year power purchase agreement with National Grid. Construction is currently under way, and the transaction demonstrates, finally, that offshore wind can be a viable option in the US context. Meanwhile,

Page 24

onshore wind and solar continued to grow at a fast pace in 2015, overtaking conventional power generation volumes.

While the overall volume of transactions consummated in 2015 in the project finance market is impressive, the volatility seen in the broader debt and equity markets later in the year, which particularly impacted the energy sector, as well as the continued impact of low commodity prices, may lead lenders to become more cautious in 2016. Many upstream oil and gas companies are finding it difficult to access the capital markets in the current environment and may have to resort to more creative structures to finance their development activities. Asset- level “drillco” arrangements, in which a third-party agrees to fund some or all of the drilling costs associated with identified wells, have been used successfully by some market participants. Similarly, volumetric production payment transactions, which entail the sale of future production for a discounted advance payment, may be attractive for producers facing a liquidity crunch. As upstream companies look for solutions and traditional regulated lenders continue to face scrutiny with respect to their exposure to the energy sector, it can be expected that the importance of alternative providers of capital, such as debt funds and other asset managers, will continue to grow. The situation may not be as dire in the midstream sector, but the challenging environment for producers is expected to reduce the pace of development with respect to new pipeline infrastructure and related assets.

On the bright side, the extension of the tax credits in late December is certain to increase the level of activity in renewables over the next few years. With greater certainty around the available incentives and the continued decline in prices for solar panels and wind turbines, the sector should continue to be attractive for financiers and give rise to innovation, such as the further expansion of the solar securitization market. In light of these developments, it will be interesting to see whether merchant gas facilities will still generate as much interest from project finance lenders as they have in recent years.

Bankruptcy Developments in the Energy Sector

Crashing commodities prices for oil and other raw products generated a high number of energy- related bankruptcies and out-of-court restructurings in 2015 and early 2016. Oil prices set new record lows throughout 2015 and broke the $26 threshold in very early 2016. As commodities prices remain depressed and, in some instances, continue to fall, the number of bankruptcies is expected to rise.

In the oil and gas industry, while increasing supply plays the most visible role in falling prices, lower demand in China and other large economies also plays a significant part in driving companies to seek restructuring solutions. In 2015, a significant number of issuers in the industry engaged in up-tier exchanges in which the issuers issued new second lien debt in exchange for unsecured debt at significant discounts to the face value of the unsecured debt. In addition, a total of 42 companies in the oil and gas industry filed for bankruptcy in the U.S. and Canada. Baker Botts represented three oil and gas industry debtors in 2015: Global Geophysical Services, Inc., (“GGS”) a provider of seismic data services; Hercules Offshore, Inc., a publicly- traded shallow-water drilling and marine services company; and New Gulf Resources, LLC, an E & P company based in Tulsa, Oklahoma with drilling operations in the East Texas Basin. Each

Page 25

of these companies faced challenges created by the volatile commodities markets, and both GGS and Hercules Offshore have already emerged successfully from chapter 11. As oil prices continue to fall, more companies will seek restructuring solutions.

Lower commodities prices affect industries beyond oil and gas. Companies associated with the manufacture, production, and sale of other raw products have experienced similar downward pressure. For example, the price of aluminum fell to six-year lows in 2015, in part driven by increased supply from Chinese producers backed by government subsidies. This increase in supply, among other factors, drove Sherwin Alumina Company, LLC to file for bankruptcy in early 2016.

The effects of these commodities-driven bankruptcies often reach companies providing support services as well. The struggles of oil and gas service companies are well documented, but the impact of reaches even further. For example, Baker Botts currently represents a cogeneration power plant supplying power to Sherwin Alumina. The struggles of the commodity-dependent debtor directly impact the operations of other companies not immediately considered to bear commodity-price risk.

Bankruptcy exit solutions are also more difficult in light of global market conditions. For example, as discussed in more detail above, in 2015 Energy Future Holdings Corporation (EFH) negotiated a transaction with an investor consortium to satisfy approximately $42 billion in debt and exit bankruptcy by restructuring the ownership of Oncor through a REIT to unlock its true value. Baker Botts represents Hunt, the leader of the investor consortium.

Environmental Regulation

EPA Moves Forward with Greenhouse Gas Regulations for Fossil Fuel-Fired Power Plants

On October 23, 2015, EPA published two final rules regulating greenhouse gas (“GHG”) emissions for the first time. One rule sets new source performance standards for GHG emissions (“GHG NSPS”) from new, reconstructed, modified fossil fuel-fired electric generating units (“EGUs”). The other rule requires that states reduce GHG emissions from existing fossil fuel- fired electric generating units (the “Clean Power Plan”). The rules took effect on December 22, 2015.

The GHG NSPS for steam generating units and stationary combustion turbines applies to new units that commenced construction after January 8, 2014 and units that were reconstructed or modified after June 18, 2014. EPA set a GHG NSPS of 1,400 pounds of CO2 per megawatt‐ hour on a gross‐output basis (“lbs CO2/MWh‐g”) for new steam generating units and 1,000 lbs CO2/MWh‐g for new baseload stationary combustion turbines. EPA also set a 120 lbs CO2/MMBtu standard for new non-baseload stationary combustion turbines. These performance standards apply to each unit nationwide.

The Clean Power Plan requires that states reduce carbon dioxide (“CO2”) emissions from existing fossil fuel-fired EGUs from 2022 to 2030. EPA established national performance rates of 1,305 lbs CO2 per MWh for steam generating units and 771 lbs CO2 per MWh for stationary combustion turbines (“subcategory rates”). EPA calculated these performance rates based on

Page 26

what it asserts is achievable through the “best system of emission reduction.” EPA determined that the best system of emission reduction for reducing CO2 emissions from existing fossil fuel- fired EGUs includes:

. heat rate improvements at existing coal-fired units;

. re-dispatch of existing coal-fired generation to existing natural gas combined cycle units; and

. increased renewable energy sources.

EPA assigned states an emissions reduction goal by applying the subcategory rates to a state’s unique generation mix. State goals range from a seven percent reduction for Connecticut to a forty-five percent reduction for North Dakota. States must submit plans to EPA by September 6, 2016 (with the possibility of a two-year extension) detailing how they will achieve their emission reduction goals by 2030. A state may choose to apply the subcategory rates to each unit in its state, but states have the discretion to allow sources to achieve subcategory rates through a variety of other mechanisms, including emissions trading, increased renewable generation, increased nuclear generation, and increased end-use energy efficiency. If a state fails to submit a plan to EPA, then EPA will issue a federal plan to impose the required emissions reductions.

EPA estimates that the Clean Power Plan will reduce CO2 emissions by 32 percent from 2005 levels. The Agency projects that by 2030 the regulation will cost $8.4 billion annually and will provide over $34 billion in benefits.

Numerous states and industry petitioners are challenging both the GHG NSPS and the Clean Power Plan in the D.C. Circuit on multiple grounds. With respect to the Clean Power Plan, petitioners allege that EPA cannot consider emission reductions measures “outside the fenceline” of a fossil fuel-fired EGU, such as re-dispatch to natural gas combined-cycle units, renewable energy generation, and emissions trading when setting performance standards and state goals. Moreover, EPA has infringed on state’s authority to balance the statutory factors in setting emission limits for particular units by setting stringent goals. Some petitioners argue that the emissions reductions required under the rule are not achievable in the allotted time, particularly considering the additional natural gas and transmission infrastructure required. At the same time, some states and environmental groups have expressed support for the Clean Power Plan. Eighteen states have intervened in support of EPA in the Clean Power Plan litigation.

On January 21, 2016, the D.C. Circuit denied motions to stay the Clean Power Plan. However, the court established an expedited briefing schedule that will be completed in April 2016. Oral argument will be held on June 2, 2016, which means that a decision could be announced as early as September or October.

State and industry petitioners subsequently sought a stay of the Clean Power Plan from the U.S. Supreme Court. On February 9, 2016, the Supreme Court granted the application for a stay. The stay will remain in place until the Supreme Court either denies a petition for certiorari from the D.C. Circuit’s ruling or grants the petition for certiorari and enters its own judgment. We expect the stay to remain in effect until at least early 2017 and, if the Supreme Court grants certiorari,

Page 27

until late 2017 or early 2018. While the stay was granted on a 5 - 4 vote, Justice Scalia’s recent death has no impact on the continued applicability of the stay.

FERC

Federal Energy Regulatory Commission

The Federal Energy Regulatory Commission (FERC) is in a period of transition. In April 2015, Commissioner Norman Bay, a former U.S. Attorney (New Mexico) who had previously served as FERC’s Director of the Office of Enforcement, was elevated to the position of Chairman, succeeding acting Chairman Cheryl LaFleur. Commissioner LaFleur remains on the Commission. In October 2015, after serving two terms, Phil Moeller left the Commission to become Senior Vice President of Energy Delivery and Chief Customer Solutions Officer at the Edison Electric Institute. In January 2016, Commissioner Tony Clark announced that he will not seek a second term and will depart the Commission when his term expires June 30, 2016. President Obama has not yet announced nominations to replace the two Republican commissioners.

In December 2015 testimony before the U. S. House of Representatives Energy and Commerce Subcommittee on Energy and Power, Chairman Bay stated that his priorities for the upcoming year include: (1) promoting greater efficiency, competition, and transparency in the wholesale markets; (2) improving grid reliability through physical and cybersecurity measures and coordination of electric and gas markets; and (3) incenting the development and facilitating the permitting of new infrastructure. Major developments and initiatives related to FERC are summarized below.

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.

Page 28

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 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.

Supreme Court Decisions Addressing FERC’s Jurisdiction

Over the last year, the Supreme Court of the United States (“Supreme Court”) issued two opinions that clarified the extent of FERC’s jurisdiction under the Natural Gas Act (“NGA”) and the Federal Power Act (“FPA”). The Supreme Court also granted certiorari to review an opinion issued by the U.S. Court of Appeals for the Fourth Circuit that upheld a district court decision invalidating a state program to subsidize the entry of new generation in the wholesale market. The Supreme Court’s decisions, and the case pending before the Supreme Court, are discussed below.

Federal Energy Regulatory Commission v. Electric Power Supply Association, 577 U.S. ___ (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.

Page 29

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 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 FPA 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.

Oneok, Inc. v. Learjet, 575 U.S. __ (2015).

On April 21, 2015, the Supreme Court affirmed a ruling by the U.S. Court of Appeals for the Ninth Circuit that state-law antitrust claims against interstate natural gas pipelines are not pre- empted by the NGA. The state-law antitrust claims were brought by a group of manufacturers, hospitals, and other institutions that bought natural gas directly from interstate pipelines.

The petitioners, consisting primarily of interstate pipeline and marketing and trading companies, had argued to the Supreme Court that state antitrust lawsuits “are within the field that the [NGA] pre-empts” because they target anti-competitive activities that affect wholesale rates. The Court disagreed in a 7-2 opinion delivered by Justice Breyer, ruling that “where (as here) a state law can be applied to nonjurisdictional [retail] as well as jurisdictional [wholesale] sales, we must proceed cautiously, finding pre-emption only where detailed examination convinces us that a matter falls within the pre-empted field as defined by our precedents.” According to the Supreme Court, when an activity affects both wholesale and retail sales it must consider the target at which the state law aims to determine whether it is pre-empted. Applying that test, the Supreme Court found that the state antitrust claims brought by the respondents were aimed at practices affecting retail prices, and were based on laws that were broadly aimed at all businesses in the marketplace rather than specifically targeted to the natural gas industry. As a result, the Supreme Court found respondents’ claims fell outside of the regulatory field occupied by FERC and were not preempted by the NGA.

Page 30

Hughes v. Talen Energy Marketing, LLC, cert. granted sub nom. Hughes v. PPL EnergyPlus, LLC, 136 S. Ct. 382 (U.S. Oct. 19, 2015) (No. 14-614).

CPV Maryland, LLC v. Talen Energy Marketing, LLC, cert. granted sub nom. CPV Maryland, LLC v. PPL EnergyPlus, LLC, 136 S. Ct. 356 (U.S. Oct. 19, 2015) (No. 14-623).

In 2014, the U.S. Court of Appeals for the Fourth Circuit affirmed a district court judgment invalidating a Maryland Public Service Commission (“PSC”) order requiring three electric distribution companies to enter into long-term agreements with a new generator to guarantee the price the generator received for both capacity and energy sold in the wholesale market operated by PJM Interconnection, LLC (“PJM”). The Fourth Circuit found that the Maryland PSC “functionally” set the new generator’s rate for wholesale capacity and energy, effectively supplanting the PJM market rate with an alternative rate set by the state. Accordingly, the Fourth Circuit held that the Maryland PSC was preempted under the FPA’s grant of exclusive authority to FERC to regulate the rates of wholesale sales of electric capacity and energy. Both the Maryland PSC and the generator petitioned for certiorari, which the Supreme Court granted on October 19, 2015.

The questions presented to the Supreme Court are:

. When a seller offers to build generation and sell wholesale power on a fixed-rate contract basis, does the FPA field pre-empt a state order directing retail utilities to enter into the contract?

. Does FERC’s acceptance of an annual regional capacity auction preempt states from requiring retail utilities to contract at fixed rates with sellers who are willing to commit to sell into the auction on a long-term basis?

Oral argument is scheduled for February 24, 2016. Given that many states have undertaken various programs to promote the development of new resources or the retention of existing resources, the Supreme Court’s decision will inform permissible state action as applied to generation resources that participate in organized wholesale markets regulated by FERC.

Connected Entities Rulemaking and Reporting by Market Participants

On September 17, 2015, FERC issued a notice of proposed rulemaking (“NOPR”) that seeks to require each regional transmission organization (“RTO”) and independent system operator (“ISO”) to deliver to FERC electronic data on an ongoing basis from their respective market participants that would (1) list their “Connected Entities,” (2) describe the nature of the relationship with each Connected Entity, and (3) identify each market participant using a common alpha-numeric identifier. FERC stated that the data collection would enhance transparency and assist FERC in screening and investigating cases involving market manipulation by providing the Office of Enforcement with a more complete view of the relationships between market participants and the incentives underlying their trading activities. The NOPR specifically notes that the targeted information will enhance FERC’s ability to identify and prosecute “cross-commodity” market manipulation, a common theory of many of FERC’s largest enforcement actions in recent years.

Page 31

In order to incorporate the new data submission requirement, FERC proposes that each RTO and ISO make a compliance filing setting forth in their respective tariffs a requirement that market participants submit a list of their Connected Entities, which would be defined to include: (1) an entity that directly or indirectly owns, controls, or holds with power to vote, 10% or more of the ownership instruments of a market participant, or an entity 10% or more of whose ownership instruments are owned, controlled, or held with a power to vote, directly or indirectly, by a market participant; (2) the chief executive officer, chief financial officer, chief compliance officer, and the traders of a market participant; (3) an entity that is the holder of a debt interest or structured transaction that gives it the right to share in the market participant’s profitability above a de minimis amount; or (4) entities that have entered into an agreement with a market participant that relates to the management of resources that participate in FERC-jurisdictional markets, such as tolling agreements, operating agreements, and management agreements. As proposed, this new rule could impose substantial, new record-keeping and reporting burdens on market participants and investors and potentially could lead to penalties for any failure to provide complete and accurate information.

In December 2015, FERC held a technical conference to answer questions and provide further explanation of the Connected Entities NOPR, and in late January 2016, parties submitted written comments to FERC on the proposed rule.

Numerous coalitions, trade groups and industry representatives argued in their written comments that the Connected Entities NOPR, as currently drafted, would be costly and time-consuming to implement, is overly vague, and is not the right tool to achieve the objectives identified by FERC. Many commenting parties also argued that FERC could issue a rule with a more limited definition of Connected Entity that would impose far less of a burden on market participants and be equally effective at providing the desired transparency. Some parties also filed comments in support of the proposed rule, but most of those parties still argued for some clarification, narrowing or exclusions to application of the proposed rule.

There is no timetable for final FERC action on the Connected Entities NOPR. Considering the focus the Commission and Chairman Bay have placed on the agency’s enforcement capabilities, however, and the enforcement-related objectives identified in the Connected Entities NOPR, it seems likely that there will be further action and a final order on the Connected Entities NOPR in 2016.

Deliverability of Fuel Supply for Fossil-fired Electric Generators

The industry saw a continued focus on fuel deliverability in 2015, including further evolution of FERC’s natural gas-electric coordination studies, and major developments in the statues and regulations affection the exportation and transportation of crude oil.

Natural Gas-Electric Coordination

FERC took the next major step in advancing its efforts to enhance reliability of the electric grid through better coordination of gas and electric supply. In two final rules issued in 2015, FERC amended its regulations to adopt industry standards that moved the nationwide deadline for submitting nominations during the Timely Nomination Cycle (i.e., the first opportunity for

Page 32

scheduling natural gas transportation service during a gas operating day (Gas Day)) from 11:30 a.m. Central Clock Time (CCT) to 1:00 p.m. CCT. The standards adopted by the final rule also modified the intraday nomination timeline, adding an additional intraday scheduling opportunity (the “Intraday 3 Nomination Cycle”) during the Gas Day. FERC further amended its regulations to require pipelines to permit shippers to sign multi-party contracts, pursuant to which the contracting shippers would be able to share capacity under a single contract for which those shippers would be jointly and severally liable for payment.

In the final rulemaking proceedings, FERC declined to adopt a proposal that would have more closely aligned the Gas Day with the electricity operating day. The proposal would have made the start of the Gas Day earlier (moving it from 9:00 a.m. to 4 a.m.) so that electric generators could respond to reductions or interruptions in the midst of the morning electric ramping period. FERC found that moving the start of the Gas Day was not supported by the evidence of the, and that the lack of alignment between the start of the gas and electric nominating cycles had only been shown to have caused problems in isolated markets.

With the completion of the rulemakings discussed above, FERC has addressed two of the four primary areas it identified in 2013 for further study or rule development to enhance gas and electric coordination. FERC addressed the first area in a 2013 rule that expressly authorized the day-to-day sharing of non-public, operational information between electric transmission operators and interstate natural gas pipelines. Other than the changes to its regulations related to multi-party contracts, FERC has yet to formally study or propose rules to address (1) the lack of alignment between firm and non-firm gas transportation products and electric market commitments, or (2) regional differences in resource mix, climate, scheduling, and other factors.

Developments in Crude Oil Export and Transportation Policy

Two major developments occurred in 2015 that could have profound impacts on the crude oil production sector. First, in December 2015, the President signed into law legislation lifting the decades-old ban on the exportation of unprocessed U.S. crude oil. Effective immediately, companies can begin exporting most types of crude oil produced in the U.S. without the need to seek any export permits from the federal government.

Second, on May 1, 2015, the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a final rule adopting requirements focused on the safe transportation of flammable liquids, including crude oil and ethanol, by rail (Final Rule). The Final Rule necessitates extensive retrofitting of existing railroad tank cars under a relatively aggressive timeline, high standards for new construction of tank cars, and stringent requirements for enhanced braking systems for certain trains. The new regulations have far-reaching and costly implications for the U.S. fuel transportation industry and producers in regions served by rail tank car transport. The Final Rule became effective in July 2015.

FERC Enforcement Activities

In 2015, the Federal Energy Regulatory Commission assessed civil penalties against several entities that elected to pursue litigation in the United States District Courts rather than settle or

Page 33

litigate the allegations before FERC. If those proceedings are resolved through litigation, they should either affirm or curtail FERC’s expansive view of its enforcement authority.

Powhatan Energy Fund, LLC

FERC issued an order Assessing Civil Penalties alleging that Powhatan Energy Fund, LLC, Houlian “Alan” Chen, HEEP Fund, Inc. and CU Fund, Inc. violated FERC’s Anti-Manipulation Rule by engaging in fraudulent Up-To Congestion trades in the PJM market in the summer of 2010. FERC determined that the respondents had engaged in wash trades that did not involve economic risks to improperly collect certain market payments. FERC assessed a total of $29.8 million in civil penalties and $4,718,784 in disgorgement.

FERC filed a petition in the U.S. District Court for the Eastern District of Virginia to enforce its Order on July 31, 2015. On October 19, 2015, the respondents filed a motion to dismiss the petition. On January 8, 2016, the court denied that motion without prejudice and on January 15, 2016, the court scheduled a settlement conference for April 12, 2016.

City Power Marketing, LLC

FERC issued an Order Assessing Civil Penalties against City Power Marketing, LLC and its owner K. Stephen Tsingas, alleging violations of FERC’s Anti-Manipulation Rule by engaging in fraudulent Up-To Congestion trades in the PJM market during the summer of 2010. FERC determined that the respondents engaged in three types of trades to improperly collect Marginal Loss Surplus Allocation (“MLSA”) payments intended for bona fide Up-To Congestion trades: (1) round-trip trades that constituted wash trades, (2) trading between export and import points that had the same prices, and (3) trading between two points (which had minimal price differences) not to profit from spread changes but instead for the purpose of collecting MLSA payments. FERC also found that City Power had violated section FERC’s regulations by making false and misleading statements and material omissions in its communications with Enforcement staff to conceal the existence of prevalent instant messages. FERC assessed $14 million in civil penalties against City Power and $1 million against Tsingas and ordered disgorgement of $1,278,358 in unjust profits, plus interest. On September 1, 2015, FERC filed a petition in the U.S. District for the District of Columbia to enforce FERC Order. On November 2, 2015, the respondents filed a motion to dismiss the petition, and that motion remains pending with the court.

Barclays Bank, PLC

FERC issued an Order Assessing Civil Penalties on July 16, 2013. In the order, FERC determined that Barclays Bank, PLC and several of its traders had violated FERC’s Anti- Manipulation Rule by engaging in loss-generating trading of next-day, fixed-price physical electricity on the Intercontinental Exchange with the intent to benefit financial swap positions at primary electricity trading points in the western United States. FERC assessed civil penalties of $435 million against Barclays and $18 million against the named traders and ordered Barclays to disgorge $34.9 million in unjust profits, plus interest. On October 9, 2013, FERC filed a petition in the United States District Court for the Eastern District of California to enforce the civil penalty assessment. The respondents, in turn, filed a motion to dismiss the complaint or transfer

Page 34

venue, which the court denied in full on May 20, 2015. The court held that: 1) the manipulative scheme was jurisdictional to FERC and not within the Commodity Futures Trading Commission’s exclusive jurisdiction; 2) the occurrence of transactions on an open market is not a defense to manipulation; 3) the Federal Power Act’s anti-manipulation provision, 16 U.S.C. section 824v, applies to individuals; 4) venue was proper in the Eastern District of California; 5) transfer to the Southern District of New York was not warranted; and 6) the statute of limitations had not run. On October 2, 2015, the court issued a scheduling order indicating that it will proceed with this case by reviewing FERC’s Order (and underlying administrative record) and will also consider whether a determination as to this penalty assessment requires supplementation of the record submitted by FERC and/or alternative means of fact-finding.

Lincoln Paper & Tissue, Inc.

FERC issued two Orders Assessing Civil Penalties in which it determined that Lincoln Paper and Tissue LLC, Competitive Energy Services LLC, and Richard Silkman had violated FERC’s Anti-Manipulation Rule in connection with a demand response program. FERC found that respondents had engaged in a scheme to fraudulently inflate Lincoln’s energy load baselines and then offer load reductions against that inflated baseline. FERC assessed civil penalties of $5 million against Lincoln, $7.5 million against CES, and $1.25 million against Silkman and ordered disgorgement of $379,016 from Lincoln and $166,841 from CES, plus interest. On December 2, 2013, FERC filed two petitions in the U.S. District Court for the District of Massachusetts to enforce those penalty assessment orders (one against Lincoln and another against CES and Silkman). The Court has scheduled a hearing on the respondents’ motion to dismiss for February 24, 2016.

Maxim Power Corporation

On May 1, 2015, FERC issued an Order Assessing Civil Penalties for violations of FERC’s Anti- Manipulation Rule. A civil penalty of $5 million was assessed against Maxim and a civil penalty of $50,000 was assessed against Kyle Mitton, an energy analyst at Maxim. FERC alleged that the respondents engaged in a scheme to mislead the ISO-NE market monitor to collect make- whole payments for reliability dispatches based on the price of oil when Maxim’s plant actually burned less expensive gas. FERC filed a petition to enforce the penalties on July 1, 2015 with the U.S. District Court of the District of Massachusetts. The defendants filed a motion to dismiss, which remains pending before the Court.

FERC also settled several matters related to the electric industry that included violations of reliability standards, violations of FERC’s Anti-Manipulation Rule, and violations of FERC’s Prohibition of Electric Energy Market Manipulation.

Western Electricity Coordinating Council

FERC approved a settlement with Western Electricity Coordinating Council (“WECC”) on May 26, 2015 related to the 2011 outage that occurred in Southern California, Arizona and Baja California, Mexico leaving five million people without power for up to twelve hours. WECC agreed to pay a $16 million civil penalty. FERC resolved findings related to system operating limits and interconnection reliability operating limits.

Page 35

California Independent System Operator

FERC approved a Stipulation and consent Agreement on November 28, 2014 that resolved an investigation of California Independent System Operator (“CAISO”) resulting from a September 8, 2011 power outage that left 2.7 million customers without power for multiple hours. FERC investigation determined that the entities responsible were not prepared to ensure reliable operation or prevent cascading outages in the event of a single contingency. CAISO agreed to pay $6,000,000 in a civil penalty.

Coaltrain Energy L.P.

On September 11, 2015, FERC published a “Staff Notice of Alleged Violations” that Coaltrain Energy L.P., its co-owners Peter Jones and Shawn Sheehan, its traders Robert Jones, Jeff Miller, and Jack Wells as well as its analyst Adam Hughes violated FERC’s Anti-Manipulation Rule by devising and executing a scheme to manipulate the Up-To Congestion trading in PJM Regional Transmission Organization between June and September 2010.

EtraCom LLC

On July 27, 2015, FERC published a “Staff Notice of Alleged Violations” that EtraCom LLC and Michael Rosenberg violated FERC’s Anti-Manipulation Rule by engaging in manipulative virtual trading at the New Melones Intertie in the California Independent System Operator footprint during May 2011.

ERCOT

ERCOT saw record peak demands in 2015, and much of that demand seems to have been driven by population and economic growth as much as by weather. Nevertheless, reserve margins appear to have been sufficient, and resource adequacy discussions remained largely on the back burner. The final step in a multi-year phase-in raised the price cap (the System Wide Offer Cap) in ERCOT to $9,000/MWh effective June 2015; and the market continued to assess the performance of a new operating reserve demand curve (ORDC).

Three issues that attracted attention in 2015 were efforts to overhaul the ERCOT ancillary services market, the proposed sale of Oncor Electric in connection with the EFH bankruptcy, and a debate over whether to address load growth in the Houston area through regulated transmission construction or by relying on market incentives for the construction of new generation. The proposed sale of Oncor is addressed elsewhere in this document. The Future Ancillary Services initiative and the Houston Import Project are summarized here.

Future Ancillary Services

In November 2014, ERCOT filed Nodal Protocol Revision Request (NPRR) 667 with the Protocol Revision Subcommittee (PRS) proposing to introduce some new and redefined ancillary services. NPRR 667 responds to an increase in inverter-based generation resources, such as wind and solar, and also to new technologies that change the ways in which various generation resources can provide ancillary services. NPRR 667 would separate frequency response services

Page 36

and contingency response service, which are bundled in the current responsive reserve service. It would also recognize that fast frequency response has greater value than primary frequency response under certain system conditions and would tie the amount of primary frequency response that a resource can provide to that resource’s past performance. Non-spin reserve service would be replaced by several contingency reserve and supplemental reserve services, which would more closely track system conditions. Under NPRR 667, no single resource would be permitted to carry more than 25% of the total ERCOT system regulation requirement, thus ensuring that there are, at all times, at least four different resources providing that service.

In December 2014, NPRR 667 was tabled. Comments were filed by a number of parties in January and February of 2015. In December 2015, the Brattle Group published a cost-benefit analysis of the proposal, which can be found here: http://www.ercot.com/content/wcm/key_documents_lists/73770/2015_11_03_Brattle_FAS_BC A_Study_Results_Draft.pdf

New comments (following the Brattle report) were filed on January 25, 2016, and a workshop was held on February 1, 2016. PRS is expected to take up NPRR 667 at its February 11, 2016 meeting. If approved, it would still have to go through one or more other subcommittees and then to the Technical Advisory Committee (TAC) and the ERCOT Board.

Houston Import Project

In April 2104, the ERCOT Board of Directors voted to endorse a new transmission project—the Houston Import Project—to increase the capacity to import power into the Houston area and deemed the project critical for reliability. In May 2014, NRG and Calpine challenged ERCOT’s decision at the PUC, arguing that ERCOT had ignored its own protocols in determining the need for the new line. In November, the PUC rejected the challenge by NRG and Calpine, finding that ERCOT had followed the proper procedures. At the same time, however, the PUC voted to open a new rulemaking project to review the transmission planning process at ERCOT. NRG and Calpine appealed the PUC’s ruling. In early 2015, however, CenterPoint Energy and Cross Texas Transmission filed applications seeking certificates of convenience and necessity authorizing them to build their respective portions of the Houston Import Project. With the filing of the CCN cases, the focus of this debate shifted away from the NRG/Calpine appeal and the rulemaking toward the contested CCN cases.

In addition to challenging many of the assumptions and methodologies used by ERCOT and the utilities to support the need for the project, NRG and Calpine argued that relying on a transmission solution would disrupt the market pricing signals needed in an energy-only market to encourage generation investment in locations where it is most needed. The utilities countered that generation had not, in fact, developed in the Houston area and that the existing import paths were already showing signs of overloading. In late October 2015, the administrative law judges who heard the case recommended approving the project. The Public Utility Commissioners considered the case in a series of open meetings in December 2015 and January 2016 and ultimately voted to approve the project. As of early 2016, there has been no further movement in the NRG/Calpine appeal or in the rulemaking.

Page 37

CFTC

The Commodity Futures Trading Commission (CFTC) has implemented several requirements under the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), including transactional reporting requirements, which became effective in 2013, recordkeeping obligations, as well as central clearing requirements with respect to certain swaps. These clearing requirements are currently limited to specified interest rate and credit default swaps and do not yet extend to energy-related derivatives. Parties that enter into the affected swaps for purposes of hedging risk may elect the “end-user” exception to the clearing requirement. End- users may claim the exception by filing an annual certification with a swap data repository, including a board resolution authorizing the company to enter into non-cleared swaps.

The CFTC also has issued guidance on the extra-territorial application of its Dodd-Frank rules, explaining that it will regulate swaps involving non-U.S. subsidiaries of U.S. entities, as well as non-U.S. entities that either guarantee the swap-related obligations of their U.S. affiliates or that enter into swaps for the purpose of hedging the risks of their U.S. affiliates. The Securities Industry and Financial Markets Association, the International Swaps and Derivatives Association and the Institute of International Bankers filed a lawsuit challenging the CFTC’s cross-border application of its regulations. The United States District Court for the District of Columbia rejected the challenge, holding that the CFTC’s cross-border guidance does not “purport to carry the force of law” and is, therefore, not a “final agency action” subject to judicial review under the Administrative Procedure Act. According to the court, because the cross-border guidance is not a rulemaking, it “is binding on neither the CFTC nor swaps market participants.” Nevertheless, the court noted, if entities engaging in potentially regulated swaps act contrary to the CFTC’s policy guidance, they may be required to defend themselves from administrative action by the agency under the CFTC’s general extraterritorial authority granted under the Dodd- Frank Act. Entities entering into swaps outside the United States that nevertheless have some connection to the U.S., such as a guarantee provided by a U.S. person to one of the swap parties or a back-to-back swap involving a U.S. affiliate, will be faced with the decision of whether to comply with the CFTC’s Cross-Border Guidance, even though the agency has not provided binding rules as to when those requirements apply. The District Court’s decision indicates that the CFTC likely will not face a high hurdle in justifying extending its regulations to non-U.S. swaps with a connection to the U.S., and that a cautious swap participant will treat the cross- border guidance as a strong indication of the way the CFTC will apply its regulations in a specific case.

The CFTC has revised its prior guidance on regulation of physical commodity transactions that contain embedded volumetric optionality. Previously, it had announced that it would not regulate such transactions where the optionality cannot be severed and marketed separately from the transaction, both parties are commercial parties and intend to settle the transaction physically, and the exercise or non-exercise of the option is based primarily on physical factors or regulatory requirements outside the control of the parties. In May 2015, the CFTC clarified that the parties’ intentions should be evaluated at the time of contracting rather than each time the option is exercised, and that the optionality need not be entirely “outside the control of the parties” so long as the optionality is primarily intended to address potential variability in a party’s supply of or demand for the commodity. This recognizes that the parties can have some role in deciding

Page 38

whether to exercise the optionality, so long as that decision is not driven by addressing price risk. Where parties to an option do not satisfy these factors, the CFTC has announced that it will more lightly regulate commodity trade options in which the parties intend that, if exercised, the option will be physically settled. Trade options between non-swap dealers need only be reported on an annual basis (on March 1) rather than a transaction-by-transaction basis.

The CFTC decreased from four Commissioners to three in 2015. In August 2015, Mark Wetjen, a Democrat whose term began in 2011, left the Commission.

Mexico Implements New Wholesale Power Market

On September 8, 2015, Mexico’s Secretary of Energy published the Bases of the Electric Market (“Bases”). The Bases outline the implementation and operation of the new wholesale power market, parts of which commenced operation in January 2016. Under the Bases, the Centro Nacional de Control de Energía (“CENACE”) will operate the wholesale power market, which will include markets for:

. Electricity: The short-term energy market will be comprised of a day-ahead market, a real-time market and, in a second stage, an hour-ahead market. The short-term energy market will allow market participants to submit offers to sell and purchase energy and ancillary services. CENACE will utilize sale and purchase offers to carry out economic dispatch for each submarket. The economic dispatch algorithm will calculate locational marginal prices (“LMPs”), which will be comprised of marginal energy, congestion and loss components.

. Financial Transmission Rights: Financial Transmission Rights will grant market participants the right to charge and the obligation to pay the amount resulting from the differences in value between the marginal congestion components of LMPs between an origin node and a destination node, excluding certain costs. Financial Transmission Rights will be defined in four-hour blocks. With the exception of grandfathered (legacy) Financial Transmission Rights, Financial Transmission Rights will be sold in auctions.

. Capacity: The capacity balancing market will be an annual auction in which market participants buy and sell capacity.

. Clean Energy Certificates: CENACE will operate a spot market for clean energy certificates. The clean energy certificate market will be operated at least annually. Separately, parties may buy and sell clean energy certificates through independently negotiated bilateral contracts.

. Medium and Long-Term Auctions: Medium-term auctions will offer three-year electricity and capacity contracts. Long-term auctions will offer fifteen-year contracts for electricity and capacity, and twenty-year contracts for clean energy certificates. Both medium- and long-term auctions will be held at least annually, although auctions may occur more frequently if required by the business practice manuals (to be released at a future date).

Page 39

In addition to the markets described above, market participants may enter into bilaterally negotiated contracts for electricity, capacity and clean energy certificates. Market participants may also structure bilateral contracts conveying the same rights and obligations as Financial Transmission Rights issued by CENACE.

The historical lack of a private market for electricity in Mexico has led to significantly higher electricity prices in Mexico than in the United States. Indeed, on the first day of trading in the day-ahead market for Baja, California, power sold at an average price of 354.69 pesos ($19.20) a megawatt-hour—a price close to the day-ahead prices in Texas for the same day. Given that Baja, California is much less populated than other regions of Mexico, some observers have hypothesized that prices will be even higher in more high-demand, urban centers when those regions join the market. These initial results suggest that Mexico’s new power market will provide a multitude of opportunities for foreign investors and new participants.

Distributed Generation

2015: A Mixed Year for Distributed Generation as Growth Continues

In 2015, 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), which recently began reporting monthly state- level distributed generation data, estimates that solar energy produced 3.6 million MWhs in September 2015, of which 33% was generated by small-scale installations. EIA, Today in Energy - EIA Electricity Data Now Include Estimated Small-Scale Solar PV Capacity and Generation, available at: http://www.eia.gov/todayinenergy/detail.cfm?id=23972 (Dec. 2, 2015). The EIA also reported growth in both small-scale and utility-scale distributed solar generation capacity across the residential, commercial, and industrial sectors. The growth is generally expected to continue in 2016; EIA projects a 9.5% increase in all renewable electric generation resources for 2016. EIA, January 2016 Short Term Energy Outlook - Electricity and Heat Generation from Renewables, available at https://www.eia.gov/forecasts/steo/report /renew_co2.cfm (Jan. 12, 2016). As distributed generation grew in deployment in 2015, it experienced mixed success from a regulatory perspective, and regulatory opportunities and challenges are expected to be a hallmark of 2016.

Extension of the PTC and ITC

The extension of the federal Production Tax Credit and the Investment Tax Credit for solar and wind projects in late 2015 by Congress marked an important victory for distributed generation. The 30% residential and commercial solar ITC was set to expire at the end of 2016, but has now been extended at the 30% level for projects which commence construction by the end of 2019, with step-downs in the credit level then occurring through 2022. This is covered in more detail in the section above on Renewables.

Regulatory Battles over Net Metering

At the state-level, net metering and retail electric rate policies supporting the development of distributed solar generation experienced setbacks or challenges. Net metering allows an electric

Page 40

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 Hawaii, Nevada, and California 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 Hawaii, the Public Utilities Commission issued an order on October 12, 2015 approving a reduction in the net metering credit for new residential solar customers interconnecting the service territories of Hawaiian Electric Industries utilities (existing customers are grandfathered and will continue to receive the higher credit). Haw. Pub. Util. Comm., Decision and Order No. 33258, Docket No. 2014-0192 (2015). The new credit will be set at between about 15 and 28 cents depending upon location, down from 26 to 38 cents. In addition, new residential solar customers will have a $25.00 minimum monthly bill in recognition of the costs of maintaining distribution facilities and providing other services to the customer. The Commission’s order also established a new self-supply rate option for customers who do not export electricity to the grid, as well as a time-of-use rate option. Solar advocates supporting retail-rate based net metering credits sought judicial review of the Commission’s order in Hawaii Circuit Court, but did not prevail. An appeal of that decision is anticipated by solar advocates. The Commission’s net metering order will also be followed by a second-phase proceeding in 2016 which will consider distributed generation policy on a longer-term basis.

In Nevada, the Public Utilities Commission eliminated the retail-rate net metering credit for both existing and new customers of utility NV Energy in a controversial December 22, 2015 order. Pub. Util. Comm. of Nev., Order on Application of Nevada Power Co., et al., Docket Nos. 15- 07041, et al. (2015). In the same order, the Commission also approved increases in the basic fixed service charge for all net metering customers. The Commission’s order prompted the filing of class action lawsuits against the Commission by existing distributed generation customers who made long-term investment decisions based upon the availability of the retail net metering rate. In response to customer reaction, it also prompted NV Energy to propose to the Commission grandfathering the retail rate net metering credit for existing customers for 20 years. The Commission agreed on January 25 to reconsider its decision as to whether to grandfather existing customers, and the matter is pending.

In California, the Public Utilities Commission issued a final order on January 28, 2016 after a 3- 2 vote adopting most of its December draft proposal to retain retail-based net metering rates for customers of California’s major utilities as part of Net Energy Metering 2.0 (NEM 2.0). Calif.

Page 41

Pub. Util. Comm., Decision Adopting Successor to Net Energy Metering Tariff, Rulemaking 14- 07-002 (2016). Under NEM 2.0, distributed generation retail customers will receive the retail rate for electricity exported to the grid, less certain non-bypassable charges. A significant change from the December proposal is that NEM 2.0 customers will not have to pay for non- bypassable transmission charges, which has the result of lowering the non-bypassable charges paid by net metering customers. In addition to preserving retail net metering rates, the Commission also requires NEM 2.0 customers to be billed according to time-of-use tariffs which provide for different rates during different times of day depending on costs and demand. Under the order, Customers who receive NEM 2.0 service will be grandfathered for 20 years. The Commission will revisit future net metering policies again in 2019.

2016: A Look Ahead

In addition to regulatory fights over the value of net metering, solar advocates and utilities are squaring off on other issues. Utilities in a number of jurisdictions are considering or have proposed higher retail rates for net metering customers as part of a proposal to recover what the utilities claim are revenue shortfalls due to a drop in cost recovery from declining consumption- based charges or shifting of costs for grid maintenance and other services to customers who do not have distributed generation. Examples of these proposals are the Hawaii minimum bill and the Nevada increased basic service charges discussed above. These regulatory disputes are expected to continue in 2016.

States have also initiated proceedings to consider how to best coordinate and manage distributed generation resources, and these proceedings will reach important milestones in 2016. In New York, for example, the Reforming the Energy Vision (REV) proceeding before the New York Public Service Commission is moving along with its proposal of using utility-operated platforms (Distributed System Platforms, or DSPs) for integrating, deploying, and maximizing the value and attributes of distributed generation. New York utilities will be filing Distribution Service Implementation Plans (DSIPs) in 2016 containing their DSP proposals. This first track of the REV proceeding will consider how the DSIPs address distribution system issues and provide for the market tools required for DSPs. The Commission is also undertaking a track two of the REV proceeding to explore ratemaking policies designed to encourage deployment of distributed generation and provide utilities with adequate revenue streams in connection with operating the DSPs. This proceeding, as well as similar proceedings in other states such as California and Hawaii, are expected to progress in 2016.

Page 42

Exhibit A

Selected Utility Mergers and Acquisitions

January 1, 2013 – February 15, 2016

Premium to Reverse Date Break-Up Fee Total Market Price Break-Up Fee Management Required Announced Equity P/E Nature of Parties Transaction Consideration Structure/Other Regulatory Value NTM (% of Equity Process Value (days prior to (% of Equity Undertakings Approvals (Closed) Value) announcement) Value)

Empire District management to head regional HSR, FERC, Empire 2/9/16 $53M $65M management team; CFIUS, AR, District/ $2,389.81 $1,487.95 Cash 21.3% (1 day) 23.2x (pending) (3.56%) (4.37%) no changes to KS, MO, OK Algonquin management or and FCC employees at Empire

Maintain HSR, FERC, ITC 2/9/16 $245M $280M/$245M headquarters in CFIUS, IL, Holdings/ $11,426.90 $6,945.86 Cash/Stock 15.5% (1 day) 21.9x Competitive (pending) (3.53%) (4.03%/3.53%) MI, no force KS, MO, OK Fortis, Inc. reductions and WI

One Questar representative to be appointed to 2/1/16 each of Dominion Questar/ 23.2% (1 day $99M $154M and Dominion HSR, UT, $5,982.94 $4,396.74 Cash 19.1 Dominion prior) (2.25%) (3.5%) Midstream’s WY, ID (pending) boards; maintenance of headquarters in Salt Lake City

Premium to Reverse Date Break-Up Fee Total Market Price Break-Up Fee Management Required Announced Equity P/E Nature of Parties Transaction Consideration Structure/Other Regulatory Value NTM (% of Equity Process Value (days prior to (% of Equity Undertakings Approvals (Closed) Value) announcement) Value)

One Piedmont representative will be added to Duke’s Board of Directors; 10/26/15 Piedmont/ $125M $250M an existing 40% (1-day HSR, NC, $6,589.35 $4,794.90 Cash 30.9x member of Competitive prior) FCC (pending) Duke (2.61%) (5.21%) Piedmont’s management team will lead Duke’s natural gas operations.

Tampa Electric and NM Gas to 9/4/15 TECO/ 48% (unaffected $212.5M $326.9M HSR, CFIUS, maintain existing $10,422.48 $6,481.18 Cash price as of 24.7x FERC, NM, Competitive headquarters in 7/15/15) FCC (pending) Emera (3.28%) (5.04%) Tampa and Albuquerque

8/24/15 AGL/ $201M AGL to maintain HSR, CA, 36.3% (20-day $12,001.74 $7,924.74 Cash 21.8x N/A separate board and GA, IL, MD, Bilateral VWAP) (pending) Southern (2.54%) management team NJ, VA, FCC

UIL CEO to be UIL/ 2/26/15 $75M CEO of combined 24.6% (est. 1- entity; UIL CEO HSR, CFIUS, $4,847.02 $3,040.02 Stock/Cash 21.6x N/A Bilateral Iberdrola day prior) and 2 others to join CT, MA, FCC (12/16/15) (2.47%) (USA) Iberdrola (USA) board of directors

12/3/14 HEI/ $90M $90M HEI to maintain 21% (est. 20-day local headquarters HSR, FERC, $4,567.39 $2,601.37 Stock 15.9x Bilateral VWAP) and be managed HA, FCC (pending) NextEra (3.46%) (3.46%) locally

Premium to Reverse Date Break-Up Fee Total Market Price Break-Up Fee Management Required Announced Equity P/E Nature of Parties Transaction Consideration Structure/Other Regulatory Value NTM (% of Equity Process Value (days prior to (% of Equity Undertakings Approvals (Closed) Value) announcement) Value)

CLECO to CLECO/ 14.7% (1-day maintain local 10/20/14 prior)(strategic $120M $180M headquarters and HSR, CFIUS, Macquarie/ $4,703.54 $3,365.13 Cash process had 20.3x management; Competitive FERC, LA (pending) been previously (3.57%) (5.35%) CLECO President BCIMC disclosed) to become CEO upon closing

3 Integrys 6/23/14 Integrys/ $175M $175M HSR, FERC, 17.3% (1 day Directors to join $9,114.57 $5,684.47 Stock/Cash 19.5x WIA, IL, MI, Bilateral prior) WEC Board upon MN, FCC (6/29/15) WEC (3.08%) (3.08%) closing

Maintenance of 4/30/14 Pepco/ 19.6% (1 day $293M $180M HSR, FERC, local and regional $12,605.43 $6,912.43 Cash prior); 29.5% 22.4x DE, DC, MD, Competitive headquarters and (20-day VWAP) NJ, VA, FCC (pending) Exelon (4.24%) (2.60%) management

UNS management team to remain in place, UNS headquarters to 12/11/13 $63.9M HSR, CFIUS, 30.1% (1 day remain in Tucson UNS/Fortis $4,343.11 $2,502.68 Cash 18.4x N/A FERC, AZ, Bilateral prior) and 4 current FCC (8/15/14) (2.55%) directors of UNS to remain on UNS Board of Directors following closing

NV to continue to $56.6M (1st 6 5/29/13 NV/ operate as a 20.3% (1 day weeks) HSR, FERC, $10,688.83 $5,664.63 Cash 18.0x N/A separate subsidiary Bilateral prior) (1.0%)/$169.7 NV, FCC and maintain local (12/19/13) Berkshire M (3.0%) headquarters