FERC licensing post-Hoopa Valley Tribe ruling

In the wake of a January 2019 court ruling holding that the states and applicants for water quality certifications cannot indefinitely stall federal time limits for state action by repeatedly withdrawing and resubmitting their applications, federal energy regulators are being asked to rule that states have waived their rights to issue water quality certifications.

On January 25, 2019, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in Hoopa Valley Tribe v. Federal Energy Regulatory Commission. The court’s basic holding addresses language in Section 401 of the Clean Water Act providing that a state’s water quality certification requirements shall be waived with respect to a federally jurisdictional application if the state “fails or refuses to act on a request for certification, within a reasonable period of time (which shall not exceed one year) after receipt of such request.” In its recent ruling, the court strictly construed the one year limit for state action, saying it couldn’t be gamed by repeatedly withdrawing and refiling the application, because that would usurp the federal regulatory scheme.

At issue in Hoopa Valley Tribe are PacifiCorp’s Klamath River hydropower facilities in California and Oregon. PacifiCorp applied for relicensing in 2004, and met all milestones except state water quality certification. A 2010 settlement agreement with a consortium of stakeholders included an agreement between the states and the licensee “to defer the one-year statutory limit for Section 401 approval by annually withdrawing-and-resubmitting the water quality certification requests that serve as a pre-requisite to FERC’s overarching review.” A Native American tribe (which was not a signatory to the settlement agreement) petitioned FERC for a declaratory order that California and Oregon had waived their Section 401 authority and that PacifiCorp had correspondingly failed to diligently prosecute its licensing application for the Project. FERC rejected the tribe’s petition.

On appeal, the DC Circuit said the issue was whether a state waives its Section 401 authority when, pursuant to an agreement between the state and applicant, an applicant repeatedly withdraws-and-resubmits its request for water quality certification over a period of time greater than one year. The court then said determining the effectiveness of this scheme was “an undemanding inquiry” given the statutory language which sets a maximum of one year for states to consider the certification request. The court says that each resubmitted request wasn’t really a “new” request, so FERC acted arbitrarily and capriciously in finding that the states hadn’t failed to act. The opinion offers strong language saying states’ “deliberate and contractual idleness” cannot be used to “usurp FERC’s control over whether and when a federal license will issue.” The court remanded the case to FERC with a directive to proceed with its review of, and licensing determination for, the project.

Now, parties are invoking the Hoopa Valley Tribe ruling in requests to the Commission for orders finding that states have waived their certification rights through the withdrawal-and-resubmission process. On February 28, 2019, Exelon Generation Company, LLC requested a declaratory order that Maryland has waived its authority to issue a water quality certification for Exelon's Conowingo Hydroelectric Project, by failing to timely act on Exelon's request for certification.

Similarly, in February, Dan Dinges, president and CEO of Cabot Oil & Gas Corporation, filed a letter with the Commission, urging prompt approval of the Constitution natural gas pipeline. Dinges described dhe Constitution Pipeline, of which Cabot is one of the developers, as having been blocked by the state of New York, and noted that the DC Circuit had held in abeyance a case relating to the Constitution pipeline’s certification pending action on the Hoopa Valley Tribe case because they raised “common questions of law.” In his letter, Dinges cites the Commission’s failure to act on the Vineyard Wind capacity auction waiver request, points to New England’s constrained pipelines and fuel security concerns, and argues that “the gamesmanship of the State of New York has never been more suspect” in the wake of the Hoopa Valley Tribe ruling. He urged the Commission to act on the Constitution Pipeline. Subsequently, the Commission posted notice allowing parties to the Constitution Pipeline case an opportunity to comment on the impact of the ruling on that case.

Canada's Supreme Court rules for Quebec utility over energy contract

Canada's highest court has ruled that Quebec's provincial utility Hydro-Quebec cannot be required to renegotiate a long-term contract to buy power from a Labrador hydroelectric plant at below-market rates, even though the deal has yielded about 14 times more profit for Hydro-Quebec than for the Labrador generator.

At issue is the Churchill Falls hydroelectric plant on the upper Churchill River in Labrador, and a 1969 agreement between Hydro-Quebec and Churchill Falls (Labrador) Corporation Limited -- a company jointly owned by Newfoundland and Labrador Hydro and Hydro-Quebec. The Churchill Falls plant can generate 5,428 megawatts of power, and is one of the world's largest hydroelectric power stations.

According to former Premier of Newfoundland and Labrador Brian Tobin, during pre-construction negotiations, Hydro-Quebec told Churchill Falls that it would not allow the Labrador generator to "wheel" project power through the Hydro-Quebec grid, nor to build its own power line through Quebec to reach U.S. markets. As a result, under the terms of the 1969 agreement, Hydro-Quebec agreed to buy most of the project's power at the fixed price of $2.50 per megawatt-hour, to guarantee construction cost overruns, and to build transmission lines connecting the generators to markets, enabling the Labrador generator to sell power and to use debt financing to construct the plant. The original contract was set to expire in 2016, but included a renewal clause allowing Hydro-Quebec to extend the contract for an additional 25 years at a fixed price of $2 per megawatt-hour through 2041.

After the contract was signed, changes in the electricity market -- including oil price shocks in the 1970s, a decline in public confidence in nuclear power after a 1979 accident, and the U.S. Federal Energy Regulatory Commission's 1996 decision to require open access to transmission systems -- meant the contract's purchase price is now well below market prices. Because Hydro-Quebec sells electricity from the plant to third parties at market prices, Hydro-Quebec reaps substantial profits from the deal. For example, Hydro-Quebec reports that the average retail price for residential customers in St. John's, Newfoundland in 2018 is $120.30 per megawatt-hour. Canada's National Energy Board says the 2017 average wholesale prices for electricity imports were over $24 per megawatt-hour, with exports priced even higher at $38.58 per megawatt-hour -- over 19 times higher than the price Hydro-Quebec now pays Churchill Falls during the extended contract term. According to CBC, the contract has yielded about $28 billion in profits to Quebec, but just $2 billion for Newfoundland and Labrador.

Citing legal theories including a general duty of good faith, Nalcor Energy subsidiary Churchill Falls asked Canadian courts to order that the contract be renegotiated and the benefits be reallocated. After lower courts sided with Hydro-Quebec, the generator appealed to the Supreme Court of Canada.

On November 2, the Supreme Court of Canada rendered its judgment in the matter of Churchill Falls (Labrador) v. Hydro-Quebec. The high court found, by a 7 to 1 decision, for Hydro-Quebec, noting that the parties "bound themselves knowing full well what they were doing" and that Hydro-Quebec could insist on adhering to the contract despite the "unforeseen" increase in the power's market value.

The one dissenting judge characterized the contract as "relational" in nature, and thus said that both parties are subject to a duty of cooperation which Hydro-Quebec breached by failing to renegotiate and to more fully share the benefits of higher-than-expected market prices. He said that because "a profit imbalance of this nature and magnitude is beyond what the parties intended when they concluded the agreement", the parties had an implied obligation to cooperate in establishing a mechanism for the allocation of "extraordinary profits."

2017 FERC Report on Enforcement

Federal regulators of U.S. energy markets and infrastructure described an increase in litigation activities in the most recent fiscal year. According to the eleventh annual Report on Enforcement issued by the Federal Energy Regulatory Commission’s Office of Enforcement, the office has five cases pending in various federal district courts.

The Commission is responsible for enforcing various laws and regulations affecting energy markets and infrastructure. On November 16, 2017, staff from its Office of Enforcement presented to the Commission on the office's activities in Fiscal Year 2017 (October 1, 2016 through September 30, 2017).

According to the 2017 Report on Enforcement, the office has maintained the previous year's enforcement priorities: (1) fraud and market manipulation; (2) serious violations of reliability standards; (3) anticompetitive conduct; and (4) conduct that threatens transparency in regulated markets.

As noted in the Commission press release announcing the 2017 enforcement report, "Conduct involving fraud and market manipulation poses a significant threat to the wholesale energy markets because it undermines FERC’s goal of ensuring efficient energy services at reasonable cost, and it erodes confidence in those markets to the detriment of consumers and competitors." The report notes that conduct which is anticompetitive or which threatens market transparency "undermine confidence in the energy markets and harm consumers and competitors." It also emphasizes the importance of compliance with reliability standards established by Electric Reliability Organization NERC.

The report describes activities by each division of the Office of Enforcement, including staff negotiation of five settlements that resulted in more than $51 million in civil penalties and disgorgement of more than $42 million in unjust profits. These settlements are in addition to the Commission’s November 7, 2017, settlement with Barclays Bank and three traders that requires Barclays to pay a $70 million penalty and disgorge $35 million in unjust profits.

While noting that at least one litigation matter has settled since the close of the fiscal year, the report states that Enforcement staff continues litigating five Federal Power Act matters in United States District Courts, along with two Order to Show Cause proceedings under the Natural Gas Act. According to the report, "In total, as of the end of FY2017, counting all pending federal court matters and the two NGA OSC proceedings before the Commission, staff sought to recover $806,865,000 in civil penalties and $53,987,678 in unjust profits through seven litigation proceedings."

Looking forward, the report emphasizes that in FY2018 the Office of Enforcement will continue to pursue these priorities.

FERC assesses Coaltrain penalties

U.S. energy regulators have issued an order assessing $38 million in civil penalties for alleged energy market manipulation, plus disgorgement of unjust profits.

The case involves Coaltrain Energy, L.P., two of its individual owners, and three traders.  In January 2016, the Commission issued an Order to Show Cause and Notice of Proposed Penalty, alleging that the respondents had engaged in fraudulent transactions in PJM Interconnection L.L.C.'s energy markets.  The show cause order, and a supporting Enforcement Staff Report, also include allegations that Coaltrain made false and misleading statements and material omissions during the Commission's investigation. 

FERC's case against Coaltrain has now moved forward.  In a May 27 order, the Federal Energy Regulatory Commission found that Coaltrain and five named individuals violated section 222 of the Federal Power Act and section 1c.2 of the Commission’s regulations, which prohibit energy market manipulation, through a scheme to engage in fraudulent Up-To Congestion (UTC) transactions to garner excessive amounts of certain credit payments to transmission customers. 

According to the Commission, the Coaltrain respondents engaged in UTC trading conduct "similar to the behavior the Commission found fraudulent in its Chen and City Power orders issued last year," in that the UTCs were traded "not to profit based on price spread arbitrage, as the product was designed, but instead, to profit solely or primarily from a transmission credit that had nothing to do with the underlying product."  FERC alleges that the Coaltrain respondents "designed and implemented a fraudulent UTC trading scheme to receive excessive amounts of MLSA payments," or Marginal Loss Supply Allocation transmission credits.  In the Commission's words, "Respondents’ OCL Trades were manipulative because they were executed for the sole or primary purpose of targeting and garnering MLSA payments. Additionally, they were manipulative because they falsely appeared to PJM as being placed for the market design purpose of arbitraging price spreads, thus concealing their fraudulent nature and purpose."

The Order Assessing Civil Penalties also found that Coaltrain violated section 35.41(b) of the Commission's regulations, which in relevant part, prohibits a seller, such as Coaltrain, from submitting false or misleading information to or omitting material information from Commission staff.  The Commission found that in the course of responding to an investigation by FERC Office of Enforcement staff, Coaltrain intentionally withheld relevant documents from Commission staff while repeatedly representing to that its productions were “true, complete, and accurate.”  In particular, FERC concluded that Coaltrain held back documents recorded on its Spector 360 keystroke logging software discussing and reflecting its trading strategy, and only produced the documents to the Commission after agency staff discovered the documents' existence on their own.

The May 27 order states that based on the "seriousness of these violations," it is appropriate to assess civil penalties pursuant to section 316A(b) of the Federal Power Act in the following amounts:

$26,000,000 against Coaltrain (jointly and severally with Messrs. Peter Jones and Sheehan); $5,000,000 against Mr. Peter Jones; $5,000,000 against Mr. Sheehan; $1,000,000 against Mr. Robert Jones; $500,000 against Mr. Miller; and $500,000 against Mr. Wells. The Commission further directs Coaltrain, Mr. Peter Jones, and Mr. Sheehan to disgorge, jointly and severally, unjust profits, plus applicable interest, pursuant to section 309 of the FPA, in the amount of $4,121,894.

The Commission directed the respondents to pay the civil penalties within 60 days, or else the Commission said it will commence an action in a United States district court for an order affirming the penalty.

Supreme Court rules on state energy incentives

The U.S. Supreme Court has released its ruling on a case affecting how states may provide incentives for electric power generation.  In Hughes v. Talen Energy Marketing, LLC, the Court upheld a lower court's ruling invalidating a Maryland program to subsidize construction of new power plants.  The ruling provides important insight into how the Court views the boundary between federal and state jurisdiction over energy matters.

The Supreme Court of the United States.

The Hughes case involved a new Maryland program to encourage in-state generation capacity, and its relationship to federally blessed capacity market.  Under the Federal Power Act, the Federal Energy Regulatory Commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market, while States regulate retail electricity sales. 

For years,  Mid-Atlantic regional grid operator PJM Interconnection has held capacity auctions to identify need for new generation and compensate generators for development.  PJM's auctions have been approved by the Federal Energy Regulatory Commission under the Federal Power Act.  But due to concern that the PJM auction was failing to encourage development of sufficient new in-state generation, Maryland enacted its own regulatory program.  Under that state program, Maryland held a competitive process to select a developer for a new power plant, and required load-serving entities to enter into a 20-year pricing contract (called a "contract for differences") with the developer.  The developer would still sell its capacity to PJM, but would receive extra money under the state program to make up the difference between the PJM market price and the contract price.

But incumbent generators challenged the new Maryland program; a federal district court issued a declaratory judgment holding that Maryland's program improperly sets the rate the developer receives for interstate wholesale capacity sales to PJM.  On appeal, the Fourth Circuit affirmed, finding that Maryland's program was preempted because it impermissibly conflicts with FERC policies.  The case then came to the Supreme Court of the United States.

The Supreme Court's April 19, 2016 decision affirms the lower courts' rulings.  The Court agreed with the Fourth Circuit's judgment "that Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators."  In the majority opinion's words, "States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here."

The Hughes ruling sheds light on how the Court might view other state programs to incentivize new or clean generation.  That said, the Court emphasized that its holding in Hughes is limited -- that it rejected Maryland's program "only because it disregards an interstate wholesale rate required by FERC."  The Court explicitly said it would not address "the permissibility of various other measures States might employ to encourage development of new or clean generation," such as tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector.

The majority opinion concludes with a reminder that "[s]o long as a State does not condition payment of funds on capacity clearing the auction, the State's program would not suffer from the fatal defect that renders Maryland's program unacceptable."  This suggests one potential path for permissible state incentives for electric power generation.

US Supreme Court stays Clean Power Plan

The Supreme Court of the United States has issued an order staying the U.S. Environmental Protection Agency's Clean Power Plan regulations limiting carbon emissions from electric power plants.  As a result, the rule's effect is frozen until legal challenges to the rule are resolved in federal court.

The Supreme Court of the United States.

EPA's final Clean Power Plan rule establishes emission guidelines for states to follow in developing plans to reduce greenhouse gas emissions from existing fossil fuel-fired electric generating units.  Developed by EPA pursuant to Clean Air Act Section 111(d), the regulation prescribes carbon reductions for states.

While state-level emissions reductions are federally prescribed, the rule places states in the role of developing their own compliance plans for how to reach the required emissions reductions.  The rule was published in the Federal Register on October 23, 2015, as Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 80 Fed. Reg. 64,662.  It gave states until September 6, 2016 to file a final plan, or an initial plan with a request for an extension, for EPA review.

If implemented, the EPA says the Clean Power Plan will reduce carbon emissions from power plants by 32% below 2005 levels, or about 870 million short tons.  EPA estimates the regulation could yield public health and climate benefits worth $54 billion in 2030 alone.  As states cut back on using carbon-intensive fuels such as coal and oil, EPA projects that renewable energy will grow, with utility-scale wind and solar expected to double by 2030 under the Clean Power Plan compared to 2013 levels.

But numerous lawsuits have been filed challenging the rule, along with petitions to stay or freeze its effectiveness pending judicial review.  Last month, the D.C. Circuit Court of Appeals denied petitions for stay from parties including states, utilities and trade groups such as the American Coalition for Clean Coal Electricity.

Parties then filed petitions for stay to the U.S. Supreme Court.  Under a 2012 Supreme Court precedent, Maryland v. King, a party seeking a stay must demonstrate (1) a "reasonable probability" that the Supreme Court will grant certiorari or agree to hear the case, (2) a "fair prospect" that the Court will reverse the decision below, and (3) a "likelihood that irreparable harm [will] result from the denial of a stay."  This is a relatively high burden.

Today a majority of the U.S. Supreme Court agreed to stay the Clean Power Plan rule, by order entered in the West Virginia, et al. v. EPA, et al. case and others consolidated into the West Virginia case.  In the Court's words:

The Environmental Protection Agency’s "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units," 80 Fed. Reg. 64,662 (October 23, 2015), is stayed pending disposition of the applicant’s petition for review in the United States Court of Appeals for the District of Columbia Circuit and disposition of the applicant’s petition for a writ of certiorari, if such writ is sought. If a writ of certiorari is sought and the Court denies the petition, this order shall terminate automatically. If the Court grants the petition for a writ of certiorari, this order shall terminate when the Court enters its judgment.

The order notes that Justice Ginsburg, Justice Breyer, Justice Sotomayor, and Justice Kagan would deny the request to freeze the rule's effect.  This note reveals a 5-4 decision to issue the stay, with Chief Justice Roberts, Justice Scalia, Justice Kennedy, Justice Thomas and Justice Alito in the majority as supporting the stay.

With the Clean Power Plan's effect stayed, litigation over the rule will now proceed in the U.S. Court of Appeals for the District of Columbia Circuit.  The 27 states participating in challenges to the rule are likely cheering.  Those include Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Indiana, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Missouri, Montana, Nebraska, New Jersey, North Carolina, North Dakota, Ohio, Oklahoma, South Carolina, South Dakota, Texas, Utah, West Virginia, Wisconsin and Wyoming.  Meanwhile, the 18 states who filed in support of the EPA, along with those states who have started preparing compliance plans for the regulation, now find themselves on less certain footing.  So too do electric power generators, and others interested in energy markets.  If controversy persists, whatever decision the circuit court issues is likely to be appealed to the Supreme Court.

Court ruling cuts demand response uncertainty

Yesterday the U.S. Supreme Court issued an opinion upholding federal regulation of the compensation paid for wholesale electricity demand response.  The Court's opinion, FERC v. Electric Power Supply Assn., hinges on the distinction between wholesale and retail sales of electricity.  It provides the latest look at the boundary between federal and state jurisdiction over the electric grid.

Under the Federal Power Act, the Federal Energy Regulatory Commission is authorized to regulate "the sale of electric energy at wholesale in interstate commerce."  Its jurisdiction under the Federal Power Act does not extend to "any other sale of electric energy," such as a retail sale.  Traditionally, sales of energy directly to users are viewed as retail sales subject to state ratemaking jurisdiction, while sales of energy for resale are viewed as wholesale sales subject to federal ratemaking jurisdiction.

The case before the Supreme Court arose from a challenge by a group of generators to FERC Order No. 745.  Through that order, FERC adopted a rule requiring wholesale market operators to compensate cost-effective demand response resources for their performance at the same price paid to generators.  Last year, the D.C. Circuit Court of Appeals vacated FERC Order No. 745 on the ground that FERC lacked jurisdiction to set rates for this kind of demand response.  The D.C. Circuit implied that "wholesale" demand response was really retail in nature and thus subject only to state ratemaking jurisdiction.  FERC appealed this decision to the Supreme Court.

As described in the Supreme Court opinion, the appeal presented two legal issues:

First, and fundamen­tally, does the FPA permit FERC to regulate these demand response transactions at all, or does any such rule impinge on the States’ authority? Second, even if FERC has the requisite statutory power, did the Commission fail to justify adequately why demand response providers and electricity producers should receive the same compensa­tion? The court below ruled against FERC on both scores. We disagree.

In analyzing the first issue, the majority found that compensation for demand response directly affects wholesale prices -- "Indeed, it is hard to think of a practice that does so more."  The majority found, "A FERC regulation does not run afoul of section 824(b)’s prescription just because it affects―even substantially―the quantity or terms of retail sales."  The Court finally noted that FERC had offered substantial reasoning and arguments in support of its conclusion that demand response should be paid comparably to generation, and thus that FERC's actions satisfied the applicable standard that they not be "arbitrary and capricious."

The case now returns to the D.C. Circuit for further proceedings consistent with the Supreme Court's opinion. The most widespread direct impact of the Supreme Court in FERC v. EPSA will likely be a reduction to the uncertainty that has hung over the markets since the D.C. Circuit decision.  Market participants, consumers, aggregators, and grid operators have all been awaiting the ruling.  Some market changes, such as ISO New England's implementation of full integration of demand response, had been delayed pending a decision from the Court, as regional wholesale demand response programs hinge on FERC approvals under the Federal Power Act.  With the jurisdictional question resolved, these changes, and other refinements to regional transmission organizations' wholesale demand response programs, can now get back on track.

US Supreme Court upholds wholesale demand response

The Supreme Court of the United States has issued an opinion upholding regional electricity grid operators' ability to operate wholesale demand response programs under federal authority.  In that opinion, FERC v. Electric Power Supply Assn., the Supreme Court reversed a lower court's decision invalidating the Federal Energy Regulatory Commission's regulation of electricity demand response.   While further evolution of demand response will continue, the Supreme Court's 6-to-2 ruling puts regional wholesale demand response programs back on surer footing after the uncertainty injected by the lower court's previous ruling.  A grid portfolio including some degree of demand response can provide beneficial environmental, reliability, and economic effects compared to pure generation.  It appears relatively more likely that existing regional wholesale demand response programs may continue to operate under federal authority, and relatively less likely that a new state-driven demand response paradigm will arise.

As described in the Supreme Court opinion, wholesale electricity demand response programs pay consumers for commitments to reduce their consumption of electricity during peak demand periods or other times of scarcity or high prices.  For about 15 years, wholesale market operators have increasingly adopted wholesale demand response programs, with the blessing of both Congress and the FERC.  In 2011, the FERC issued its Order No. 745, establishing a rule requiring market operators to pay the same price to cost-effective demand response providers for conserving energy as to generators for producing it. 

But that order was challenged by an association of generators, among others.  In May 2014, the D.C. Circuit Court of Appeals issued a ruling in Electric Power Supply Association v. Federal Energy Regulatory Commission vacating Order No. 745.  Its chief logic was that FERC lacked authority to issue the order on jurisdictional grounds -- because in the lower court's view, Order No. 745 directly regulates the retail electric market.  Under the Federal Power Act, FERC is authorized to regulate "the sale of electric energy at wholesale in interstate commerce," but cannot regulate "any other sale" (i.e. any retail sale) of electricity.

But today's Supreme Court ruling held that the Federal Power Act does provide FERC with the authority to regulate wholesale market operators' compensation of demand response bids.  The Court divided its analysis of this point in three parts.

First, the Supreme Court held that the practices at issue directly affect wholesale rates.  In the Court's words, "Wholesale demand response is all about reducing wholesale rates; so too the rules and practices that determine how those programs operate."

Second, the Supreme Court noted that FERC has not regulated retail sales.  "Here, every aspect of FERC's regulatory plan happens exclusively on the wholesale market and governs exclusively that market's rules.  The Commission's justifications for regulating demand response are likewise only about improving the wholesale market."  Putting the first and second sets of conclusions together, the Court found that the rule established by Order No. 745 complies with the plain terms of the Federal Power Act.

Third, the Court noted that adopting a contrary view would conflict with the core purposes of the Federal Power Act: "The FPA should not be read, against its clear terms, to halt a practice that so evidently enables FERC to fulfill its statutory duties of holding down prices and enhancing reliability in the wholesale energy market."

The Supreme Court also addressed an alternative holding by the D.C. Circuit Court that the Order No. 745 compensation scheme is arbitrary and capricious under the Administrative Procedure Act.  The Supreme Court noted that its "important but limited role" in reviewing FERC's decision "is to ensure that FERC engaged in reasoned decisionmaking."  Noting FERC's detailed explanation of its choice to compensate demand response providers at LMP, the same price paid to generators, and its lengthy responses to contrary views, the Supreme Court held that "FERC's serious and careful discussion of the issue satisfies the arbitrary and capricious standard."

Justice Kagan delivered the Court's opinion, joined by Chief Justice Roberts and Justices Kennedy, Ginsburg, Breyer, and Sotomayor.   Justice Scalia filed a dissenting opinion, in which Justice Thomas joined, noting his belief that the Federal Power Act prohibits the FERC from regulating the demand response of "retail purchasers of power."  Justice Alito did not participate in the case.

The case now returns to the D.C. Circuit for "further proceedings consistent with this opinion." If Order No. 745 stands and FERC retains jurisdiction over the compensation paid to wholesale demand response market participants, it seems likely that existing regional wholesale demand response programs will continue to operate under federal authority.  As the Supreme Court found, these wholesale demand response programs can provide significant consumer savings when properly implemented.  How will demand response continue to evolve in the wake of FERC v. EPSA?  How does this decision reshape the boundary between wholesale (federal) and retail (state) jurisdictions?  What's next for demand response?

Maine court interprets wind energy law

Maine's highest court has issued an opinion interpreting Maine's laws governing wind energy project development.  The opinion, Champlain Wind, LLC v. Board of Environmental Protection, 2015 ME 156, is noteworthy for its analysis of "competing legislative purposes" in Maine wind energy law -- those designed to expedite the development of wind power in Maine, and those designed to protect scenic resources.

The Maine Supreme Judicial Court's December 3, 2015 opinion affirms an earlier decision by the state Board of Environmental Protection to deny a permit for the Bowers Wind Project.  In 2012 developer Champlain Wind had filed a consolidated application with the Maine Department of Environmental Protection, seeking state permits to construct the project.  As described in the opinion, that project would include 16 wind turbines with a combined generating capacity of 48 megawatts.  Geographically, the turbines fell "just within the boundary" of an area designated by the state Legislature for expedited wind energy development.  However, its turbines would be visible from nine great ponds classified as a "scenic resource of state or national significance" under state law.  Maine law gives enhanced protections to such scenic resources in wind project siting decisions affecting specified geographic areas.

After some process, the Department ultimately denied Champlain's application.  In so doing, the Department concluded that the project met all but one applicable standard.  The Department found that the project “would have an unreasonable adverse effect on the scenic character and existing uses related to the scenic character” of the nine affected great ponds.  This failure of the statutory scenic character standard led the Department to deny the requested consolidated permit.

Champlain appealed from the Department's denial to the Board of Environmental Protection.  The Board issued an order in June 2014 affirming the Department's denial.  Champlain appealed again, this time to the Maine Supreme Judicial Court.

The court's opinion on that case was published today.  Much of the court's opinion focuses on specific legal arguments in play -- for example, whether the Board could take an aggregated or "holistic approach" when considering a proposed project's impact on multiple scenic resources of state or national significance, and the level of judicial deference the court should afford the Board.

But for those interested in Maine wind energy development law, the most interesting parts of the opinion are likely those showing how the court interprets the Maine Wind Energy Act and related statutes.  As characterized in the introduction to the court's opinion,

the Board considered and balanced competing statutorily defined policies applicable to wind energy projects in Maine. The applicable statutes establish the dual policies of expediting wind energy development in defined geographic areas of Maine and at the same time providing enhanced protection for specific scenic resources. 

In its discussion, the court noted:

The generating facilities and wind turbines that make up the Project are proposed to be sited within the expedited permitting area; however, most of the nine great ponds affected by the Project—all of which are rated as outstanding or significant from a scenic perspective—are fully excluded from the expedited permitting area. Thus, as previously noted, the Board was confronted with a project that falls directly between competing legislative priorities.

The court recited the Board's consideration as having included:

• the “existing character of the surrounding area” and “significance of the potentially affected scenic resource,” see 35-A M.R.S. § 3452(3)(A), (B);
• the Legislature’s intent in balancing the goal of encouraging and expediting wind power development with the goal of protecting Maine’s scenic resources by limiting the geographic scope of the expedited permitting area; 
• the exclusion of most of the nine affected great ponds from the expedited permitting area; and 
• the unique interconnectedness of the affected great ponds, which would result in users being repeatedly confronted with views of the turbines from multiple scenic resources of state or national significance when traveling from one lake to another.

The court described these as "unique circumstances" and a "context of competing legislative priorities and unusually interconnected scenic resources."  In the court's view, presented with these circumstances and this context, it wasn't unreasonable, unjust, or unlawful for the Board to decline to issue the permit.  Because the court could not conclude that the Board acted unlawfully or arbitrarily or that the statutes compel a different result, the court deferred to the Board’s interpretation of the Maine Wind Energy Act and the statutes governing expedited permitting for grid-scale wind energy projects.

This opinion likely is most direct in its effect on those interested in the Bowers Wind Project, the parties and other stakeholders.  The Champlain Wind, LLC v. Board of Environmental Protection opinion may also catalyze renewed discussion about balancing what the court labeled "competing legislative purposes" in Maine wind energy project siting law -- on the one hand, to expedite the development of wind power in Maine; on the other, to protect scenic resources. 

Block Island offshore wind celebrated, challenged

U.S. and Rhode Island officials recently celebrated the start of construction on the Block Island Wind Farm, which is on track to be the first commercial offshore wind farm in the U.S.  The five-turbine, 30-megawatt project under development by Deepwater Wind is scheduled to come online in 2016; turbine foundation construction and other "steel in the water" activities are underway.  As a pioneer in U.S. offshore wind development, the Block Island project has survived years of permitting uncertainty and repeated legal challenges by project opponents.  But another such lawsuit was filed this week in federal court.  What does the future hold for the Block Island Wind Farm?

Project developer Deepwater Wind is owned principally by an entity of the D.E. Shaw group.  Its Block Island project is currently under construction in Rhode Island state waters about three nautical miles southeast of Block Island.  The project will feed power directly to consumers on Block Island, but also includes a 25-mile bi-directional submerged transmission cable between Block Island and the mainland. The project's finances rest in part on a power purchase agreement through which Deepwater Wind will sell power to utility National Grid.

That power purchase agreement, or PPA, has been the subject of several legal challenges.  Those challenges often cite the deal's cost: pricing for the Block Island power starts as high as 24.4 cents per kilowatt-hour, and escalates 3.5 percent annually.  These prices are more than double the typical Rhode Island energy price, for an estimated $497 million in above-market costs over the 20-year deal.

In 2009 and early 2010, the Rhode Island Public Utilities Commission rejected proposals by Deepwater Wind and National Grid, largely over cost.  The parties then returned with a revised proposal.  In 2010, TransCanada Power Marketing Ltd. unsuccessfully argued that the Rhode Island commission shouldn't consider that proposal due to constitutional infirmities in the Rhode Island law favoring renewable power contracts with in-state projects.  On August 16, 2010, the Commission issued its order approving the PPA.  After that order was appealed to the state Supreme Court, the Supreme Court issued a written opinion upholding the Commission's Order on July 1, 2011.  In 2012 and in 2015, project opponents petitioned the Federal Energy Regulatory Commission to invalidate the Rhode Island commission's action, which FERC declined to do.  Through all this, the project moved forward and ultimately began local construction earlier this year.

But the project is not yet completely out of stormy seas.  On August 14, 2015, plaintiffs with a history of engagement in some of these earlier challenges filed a lawsuit in U.S. District Court in Rhode Island.  As in previous challenges, this complaint argues that the Rhode Island Public Utilities Commission violated federal laws in approving the Block Island deal because only the Federal Energy Regulatory Commission may regulate wholesale electricity sales.  While it is possible that this case could be swiftly dismissed, if it lingers it could add uncertainty to the project until its resolution.  Last year a federal court invalidated a FERC ruling on the grounds that it impermissibly tread on state rights to set retail electricity rates.  That case, Electric Power Supply Association v. Federal Energy Regulatory Commission, has been appealed to the U.S. Supreme Court.

With construction underway, the Block Island project now has significant inertia behind it.  What impact will the recently filed lawsuit have?  Will it affect Deepwater Wind's position as "first in the water" in the race for U.S. commercial offshore wind development?

US Supreme Court considers EPA greenhouse gas emissions regulations

May the U.S. Environmental Protection Agency regulate greenhouse gas emissions from power plants and industry under the Clean Air Act?

The Supreme Court of the United States heard oral argument on this issue yesterday, in the case Utility Air Regulatory Group v. Environmental Protection Agency, Docket No. 12-1146.  How the court rules on the case will shape federal regulation of carbon dioxide and other greenhouse gas emissions in the nation.

The case arises from EPA's decision in 2010 to regulate greenhouse gas emissions from power plants and industrial facilities.  That decision stemmed from a 2007 Supreme Court ruling, Massachusetts v. EPA, requiring EPA to regulate greenhouse gas emissions from motor vehicles under Title II of the Clean Air Act.  Since 1980, EPA has held that once it regulates one type of air pollution (e.g. greenhouse gases from motor vehicles), it may (or must) broaden its regulations to cover all such emissions (e.g. greenhouse gases from all sources).  Applying this precedent in 2010, EPA found that regulating motor vehicle greenhouse gas emission standards under Title II of the Clean Air Act also compelled EPA to regulate greenhouse gas emissions under the Clean Air Act's Title I "prevention of significant deterioration" or PSD program, as well as under its Title V stationary-source permitting program.

Building on its Title II regulation of greenhouse gas emissions from cars and trucks, EPA then promulgated its Title I and Title V regulatory programs for stationary sources.  These rules regulated stationary sources emitting 75,000 tons of carbon dioxide or more per year, but triggered challenges from several states, over 70 non-governmental advocacy groups, and business interests.  While challengers raised a host of objections, one of the key substantive issues raised was whether EPA may truly regulate carbon dioxide as a "pollutant."  Challengers also mounted attacks rooted in law, questioning whether EPA's 2010 decision to regulate motor vehicle greenhouse gas emissions could legally trigger permitting requirements for stationary sources.

After the U.S. Court of Appeals for the D.C. Circuit upheld EPA's rules, challengers appealed that decision to the Supreme Court.  While the Court declined to address most of the issues challengers raised, it decided to entertain argument on one point: "Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases."

The Court's official docket for Utility Air Regulatory Group v. Environmental Protection Agency can be found here, and unofficial copies of many of the pleadings can be found on SCOTUSBlog.  While the Court has not indicated when it will rule on the case, energy and other industries are watching closely for the ultimate outcome.