The Washington Report

This report highlights key energy regulatory developments in the United States over the last year. Energy regulatory developments in 2013 in the United States impacted numerous sectors of the energy industry and addressed a wide swath of issues.  This report covers developments at the federal level, such as at the Federal Energy Regulatory Commission (FERC), the Department of Energy (DOE), the Environmental Protection Agency (EPA), Congress, and in the federal courts, as well as at the state level, such as  at public service/utility commissions and in state courts, which should be of interest to readers of the Energy Regulation Quarterly (ERQ).

I.          Energy, Climate Change, and Greenhouse Gases

Although a number of U.S. states are pursuing far-reaching initiatives to regulate and adapt to the effects of climate change and greenhouse gases, there has been no significant legislative action by Congress.  However, in 2013, President Obama began using his executive powers to set a more assertive course for the federal government.

A.          President Obama’s Climate Action Plan and Administrative Efforts

As we wrote in the “Washington Report” in the Fall 2013 issue of the ERQ,1  in June 2013 President Obama released the President’s Climate Action Plan (Climate Plan), identifying 30 steps to reduce carbon emissions, prepare for and adapt to the effects of climate change and related natural disasters, and participate in international climate change efforts—without requiring action from Congress.2 We identified four measures directly relevant to the energy sector: (1) carbon emission limits for power plants; (2) promotion of renewable energy development; (3) investment in new energy technologies; and (4) increased energy efficiency standards for federal buildings and appliances.  In January 2014, the president also used his State of the Union address to highlight his goals to promote solar energy and reduce greenhouse gas emissions.3 Although many of the Climate Plan’s initiatives remain conceptual, since the end of 2013 there have been several concrete developments.

B.          Carbon Emissions from Power Plants

Since April 2012, the EPA has been pursuing  an administrative rulemaking to set greenhouse gas emissions standards for new power plants.  When the president released the Climate Plan, he also issued a Presidential Memorandum directing the Administrator of EPA to adopt a final rule in a “timely fashion.”4 The initial form of the proposed rule5 proposed a “fuel-neutral” standard that would have required the same performance—1,000 pounds of carbon dioxide per megawatt-hour—from coal-fired plants as natural gas-fired plants.  This controversial proposal received over 2.5 million public comments, and EPA withdrew the original proposed rule and issued a new proposed rule on January 8, 2014.6

The new rule would set separate standards for: (1) utility boilers and integrated gasification combined cycle units based on partial implementation of carbon capture and storage as the best system of emission reductions, set at 1,100 pounds of carbon dioxide per megawatt-hour; and (2) natural gas-fired stationary combustion turbines, set at 1,000 pounds of carbon dioxide per megawatt-hour for larger units and 1,100 pounds of carbon dioxide per megawatt-hour for smaller units.  The public comment period closed on March 10, 2014, and a final rule is likely to be issued soon thereafter—after which it will almost certainly be challenged in court.

EPA has not proposed standards of performance for existing, modified or reconstructed sources.  However, the Presidential Memorandum directed the agency to propose such standards by June 1, 2014, and to adopt final standards by June 1, 2015. Additionally, state implementation plans to enact these standards are to be submitted to EPA by June 30, 2016.

C.          Renewable Energy

As we noted previously, the Climate Plan set a goal to double renewable energy production in the U.S. by 2020, including permitting of 10 gigawatts of additional renewable energy on federal lands by 2020.  The Bureau of Land Management (BLM), a branch of the Department of Interior (DOI), identified 19 Solar Energy Zones throughout six southwestern states in which solar energy development is planned to be prioritized.  In recent months, BLM’s program has seen successes (such as the nearly 400-megawatt Ivanpah solar project in California becoming operational)7 and setbacks (such as the first major auction of solar rights on federal land in Colorado, which failed to draw a single bid).8 As of November 2013, BLM reported over 35 pending applications for solar energy development on lands that it administers.9

D.          Conventional Generation Sources and Efficiency

Last fall, we wrote that DOE had proposed a solicitation for up to $8 billion in loan guarantees for a range of advanced fossil fuel technology projects to avoid, reduce, or sequester greenhouse gas emissions, which was finalized in December 2013.10  Projects covered by the loan guarantees are expected to include carbon capture, low-carbon power systems, and efficiency improvements, and initial submissions were expected to be received by the end of February 2014.  Also in December 2013, the Department of Agriculture finalized updates to its Energy Efficiency and Conservation Loan Program, which will provide up to $250 million for energy efficiency upgrades by rural utilities.11

E.          U.S. Supreme Court Review of Certain EPA Rules

The U.S. energy sector is closely monitoring legal developments relating to the Obama Administration’s earlier efforts to regulate greenhouse gases.  On February 24, 2014, the U.S. Supreme Court heard oral argument in Utility Air Regulatory Group v. Environmental Protection Agency.12   After a 2007 decision, Massachusetts v. Environmental Protection Agency,13  where the Supreme Court concluded that greenhouse gases from motor vehicles came within the definition of “air pollutant” under the Clean Air Act, EPA began to regulate greenhouse gas emissions from motor vehicles.  At issue in Utility Air Regulatory Group is whether EPA permissibly determined that regulation of motor vehicle emissions triggered Clean Air Act permitting requirements under the Prevention of Significant Deterioration (PSD) program for stationary sources, such as power plants, that emit greenhouse gases.

Utility industry groups, the U.S. Chamber of Commerce, and a number of states challenged a number of EPA regulations covering stationary source emitters, including what are known as the Triggering and Tailoring Rules.  During argument, the Court focused on, among other things, whether EPA had the authority to adopt the Tailoring Rule,14 under which EPA raised statutory emissions thresholds for greenhouse gases to ensure that only the largest stationary sources of greenhouse gas emissions would be covered.15  Commentary on the arguments suggests a close decision divided along ideological lines, with the more liberal justices possibly concluding that EPA acted permissibly, and the more conservative justices possibly concluding the opposite.16  As discussed above, the Obama Administration’s Climate Plan calls for other, complementary regulation of emissions from power plants.  Although the Court will not directly consider these regulations in Utility Air Regulatory Group, its decision—not expected until June 2014—may affect the scope and nature of these new regulatory efforts.

II.          DOE and LNG Exports

As reported last fall, DOE in 2013 ended a year-long hiatus in issuing authorizations to export volumes of liquefied natural gas (LNG) to countries with which the United States does not have a free trade agreement (non-FTA countries).

In the last authorization issued in 2013,17  DOE authorized Freeport to export only an additional 0.4 Bcf/day to non-FTA countries although Freeport had requested authorization to export an additional 1.4 Bcf/day to such countries.  DOE’s approval of less than the total amount requested to be authorized for export to non-FTA countries led some to speculate that DOE may intend to cap the volumes that it will authorize for export to non-FTA countries.  DOE based its determination on Freeport’s separate application to FERC for authorization to construct the liquefaction facilities, which described the capacity of the liquef action project as 1.8 Bcf/day.

DOE’s LNG export authorizations have reserved the agency’s authority to revoke (in whole or in part) a previously issued authorization, stating that “[w]e cannot precisely identify all the circumstances under which such action would be taken.”  Specifically, each authorization states that “[i]n the event of any unforeseen developments of such significance as to put the public interest at risk, DOE/FE is authorized by section 3(a) of the Natural Gas Act [NGA]… to make a supplemental order as necessary or appropriate to protect the public interest.”  The authorizations continue, “[a]dditionally, the DOE is authorized by section 16 of the [NGA] ‘to perform any and all acts and to prescribe, issue, make, amend and rescind such orders, rules and regulations as it may find necessary or appropriate’ to carry out its responsibilities.”

In response to concerns raised by LNG export proponents, leaders of the Senate Committee on Energy and Natural Resources sent a letter on August, 2, 2013 to the Secretary of Energy requesting clarification of the circumstances under which DOE might revoke or modify an export authorization.18 In the letter they cite to the NGA, which empowers DOE to “amend, and rescind such orders . . . as it may find necessary or appropriate to carry out the provisions of the NGA,”19 and to the Energy Policy and Conservation Act of 1975, which provides DOE authority to revoke or substantially modify previously authorized export licenses as the president determines appropriate and necessary.20

DOE’s Deputy Assistant Secretary issued a letter in response to the inquiry on October 17, 2013, stating:  (1) DOE “would not rescind a previously granted authorization except in the event of extraordinary circumstances,” and that it “takes very seriously the investment-backed expectations of private parties” and would not exercise its revocation authority “as a price maintenance mechanism”;  (2) DOE has never vacated or rescinded an authorization to import or export natural gas over the objections of the authorization holder, noting that such authorizations have only been rescinded when the authorization holder requested the authorization be vacated, had gone out of business, or was non-responsive to DOE’s inquiries; (3) DOE would not consider the cumulative impact of other authorizations when deciding whether to rescind an authorization; and (4) neither the NGA nor DOE regulations limit the submission of a request to suspend or revoke a final order to the parties in the prior authorization proceeding, and accordingly DOE would permit all interested parties to participate before a decision on a proposed revocation of an export authorization.21

III.         Hydraulic Fracturing

Standards and policies surrounding hydraulic fracturing (hydrofracking) for natural gas and oil continue to be developed through both regulation and state and local litigation, and are increasingly controversial.

A.          Federal Regulations

EPA has not issued federal hydrofracking regulations but is conducting a study commissioned by Congress to understand the potential impacts of hydrofracking on drinking water resources.  EPA held a technical workshop in 2013 that covered data collection and modeling, well construction, wastewater treatment and water acquisition modeling.  It issued a progress report in December 201222 and a draft report with preliminary findings is expected to be released for public comment and peer review in late 2014.

In May 2013, the DOI released an updated draft proposal that would establish hydrofracking safety standards on public lands under DOI’s control.23 The proposal updated DOI’s initial draft proposal issued in 2012, which garnered over 177,000 public comments during the initial comment period.  If adopted, the proposal would be the first federal regulations governing hydrofracking in the United States.  In November 2013, the House of Representatives passed H.R. 2728 that, if signed into law, would prevent DOI from regulating hydrofracking in states that already have passed their own regulations.24

B.          State and Local Regulations

In November 2013, a number of cities in Colorado, including Fort Collins and Lafayette, approved ballot initiatives banning hydrofracking within city limits.  The Fort Collins initiative prohibits hydrofracking and the storage or disposal of related waste products for five years, while the Lafayette initiative permanently bans hydrofracking.  Soon after the initiatives were passed, the Colorado Oil and Gas Association sued both cities claiming that the initiatives violate the requirement of uniform regulation in the state’s Oil and Gas Conservation Act.25

California and Illinois issued proposed rules for hydrofracking that represent the first state-wide regulations that would permit hydrofracking subject to regulation.  By contrast, several states, including New York and Maryland, have effective statewide moratoria on hydrofracking.  California’s proposed rules would establish standards relating to notification, groundwater monitoring, and disclosure of the types and concentrations of hydrofracking-related chemicals, and also would call for a statewide review of hydrofracking.26 The proposed Illinois regulations,27  which implement the Hydraulic Fracturing Regulation Act, would address water usage and pollution, such as generally requiring well wastewater to be maintained in tanks instead of open pits.

C.          State Litigation28

In December 2013, in Robinson Township v Commonwealth of Pennsylvania,29 the Pennsylvania Supreme Court voted 4-2 to strike down portions of the Marcellus Shale drilling law, Act 13,30  holding that several of its provisions violated the Commonwealth’s constitution.  Act 13 prohibited local regulation of oil and gas operations, reserved regulatory authority over those activities to the Commonwealth, and restricted local municipalities’ ability to dictate where companies could locate waste pits, pipelines, rigs, and compressor and processing stations.  Several parties, including municipalities and environmental organizations, brought suit seeking a declaration of unconstitutionality and a permanent injunction prohibiting application of Act 13.  An intermediary state court had handed down a partial victory for the Plaintiffs by striking down portions of Act 13 on due process grounds, thus “prohibit[ing] the Department of Environmental Protection from granting waivers of mandatory setbacks from certain types of state waters and permitting local governments to enforce existing zoning ordinances, adopt new ordinances… without concern for the legal or financial consequences.”31

In its decision, the Pennsylvania Supreme Court invalidated a number of Act 13’s core provisions, including the requirement for uniform statewide zoning standards for oil and gas operations.  Unlike the lower court, the Pennsylvania Supreme Court did not rest its decision on due process grounds and instead held that Act 13 violated the Environmental Rights Amendment of the Commonwealth’s constitution, which guarantees citizens’ rights “to clean air and pure water, and to the preservation of natural, scientific, historic and esthetic values of the environment.”32   Writing for the majority, Chief Justice Ronald D. Castille declared that Act 13 “effectively disposed of the regulatory structures upon which citizens and communities made significant financial and quality of life decisions, and has sanctioned a direct and harmful degradation of the environmental quality of life in these communities and zoning districts.”33

IV.          PPL Litigation and Electric Capacity Markets

FERC has worked with regional transmission organizations (RTOs), independent system operators (ISOs) and other stakeholders to develop capacity markets in various regions of the United States.  Among other things, such markets are designed to incent market participants to build new electric generating plants and thus increase capacity.  Two federal district court decisions, one in Maryland and one in New Jersey, struck down state programs that encouraged the construction of new gas-fired capacity in the PJM region where generating capacity was deemed insufficient by state authorities.34 The programs in both states conducted competitive solicitations and used contract-for-differences pricing schemes for capacity that offered winning bidders a fixed bid price from the local utilities.  In a nutshell, bidders were required to bid into, and sell capacity in, the PJM market, and any revenue from that sale would offset the fixed bid price.

The programs were challenged under the U.S. Constitution on Supremacy Clause and Commerce Clause grounds.  First, plaintiffs claimed that FERC has been given exclusive jurisdiction over wholesale ratemaking under the Federal Power Act (FPA), and the pricing schemes set by the states violated the Supremacy Clause.  Second, plaintiffs claimed that the state bidding requirements unfairly discriminated against out-of-state power producers in violation of the Commerce Clause.  Both the Maryland and New Jersey courts held that the pricing conflicted with FERC’s exclusive authority under the FPA and thus violated the Supremacy Clause, but that the Commerce Clause was not violated.35

The decisions are significant as they illuminate the tensions between state and federal programs to encourage the construction of new generation facilities and raise questions about the legality of mandates and renewable portfolio standard programs in other states.

V.          FERC Enforcement and Alleged Market Manipulation

FERC’s Office of Enforcement (Enforcement) had a landmark year in 2013.  As highlighted in its annual report,36 FERC continued to focus its enforcement efforts in four principal areas: (1) fraud and market manipulation; (2) serious violations of the reliability standards; (3) anticompetitive conduct, and (4) conduct threatening the transparency of regulated markets.  Enforcement opened 24 new investigations of market participants (up from 16 in 2012) and resolved 29 more with no action, a settlement, or formal enforcement action.

The year’s most significant enforcement matters came as a result of FERC’s authority to prosecute under the FPA and NGA and impose civil penalties of up to $1 million per day for market manipulation and fraud.37 These matters are briefly described below. A more detailed discussion of these matters (except Lincoln Paper and Tissue LLC et al.) can be found in the Fall 2013 issue of the ERQ.

A.          Barclays Bank PLC et al.

On July 16, 2013, FERC assessed civil penalties38 totaling $435 million and ordered $34.9 million in disgorgement against Barclays Bank PLC (Barclays) and further assessed civil penalties totaling $18 million against certain Barclays’ traders for allegedly manipulating energy markets in and around California between 2006 and 2008.  The penalty ordered against Barclays marks the largest of its kind in the agency’s history.  Barclays and the individual traders have denied FERC’s allegations and elected to challenge the penalties in federal court.

On October 9, 2013, FERC petitioned the U.S. District Court for the Eastern District of California to issue an order affirming its assessment of penalties against Barclays and the individual traders. On December 16, 2013, Barclays and the individual traders responded by filing a motion to dismiss39 FERC’s petition.  The motion raises a number of important legal questions relating to FERC’s authority to police electricity markets.  The motion, for example, argues that FERC lacks jurisdiction over the relevant transactions because they were commodity futures transactions over which the Commodity Futures Trading Commission (CFTC) has exclusive jurisdiction under the Commodity Exchange Act (CEA), and because they did not result in physical delivery or transmission of electricity, as the movants claim is required for FERC jurisdiction under the FPA.  The motion also argues that the relevant transactions were neither manipulative nor fraudulent because they were executed between willing parties in an open and transparent market, and that the individual traders cannot be held liable for manipulation because the FPA prohibits only an “entity” (not natural persons) from engaging in manipulation.  FERC’s response takes issue with these positions.  The court has not yet ruled on the motion.40  An adverse ruling for FERC on any one of these issues could significantly limit FERC’s enforcement authority.

B.          JP Morgan Ventures Energy Corporation

On July 31, 2013, FERC approved a settlement41  with JP Morgan Ventures Energy Corporation (JPMVEC) providing for civil penalties of $285 million and disgorgement of $125 million.  The settlement resolved allegations that JPMVEC manipulated certain energy markets in California and the Midwest between 2010 and 2012.  Pending the outcome in Barclays, FERC’s settlement with JPMVEC stands as the largest civil penalty assessed by FERC and paid by the subject of an enforcement investigation.

C.          B.P. America et al.

On August 5, 2013, FERC ordered42  BP America Inc., BP Corporation North America Inc., BP America Production Company, and BP Energy Company (collectively, BP) to show cause why it should not be found to have illegally manipulated a certain natural gas market in Houston from September to November 2008, be assessed penalties totaling $28 million, and be forced to disgorge $800,000 in unjust profits.  On October 4, 2013, BP filed an answer denying all wrongdoing and requesting that FERC dismiss the proceeding or, in the alternative, set the matter for a full evidentiary hearing before an administrative law judge at the agency.  BP’s request is pending before the Commission.

D.          Lincoln Paper and Tissue LLC et al.

On August 29, 2013, FERC issued orders43  assessing civil penalties of $5 million, $7.5 million, and $1.25 million against Lincoln Paper and Tissue LLC (Lincoln), Competitive Energy Services, LLC (CES), and Richard Silkman (Silkman), CES’ managing partner, respectively, alleging that they manipulated ISO New England’s demand response markets.44  The orders also sought disgorgement of unjust profits of approximately $380,000 from Lincoln and $170,000 from CES.  Each order principally found that the subjects devised and carried out schemes to collect payments for demand response without actually reducing electricity consumption from the grid.  According to FERC, the subjects collected such payments by fraudulently inflating load baselines45 and repeatedly offering load reductions at the minimum offer price to maintain inflated baselines.  FERC concluded Lincoln, CES, and Silkman made uneconomic energy purchases that served no legitimate business purpose and were designed to increase demand response payments that would not have been received absent of the uneconomic transactions.  FERC also accused Rumford Paper Company (Rumford) of similar conduct, but Rumford settled46 with the agency.

On December 2, 2013, FERC filed petitions47 in the U.S. District Court for the District of Massachusetts seeking orders affirming its imposition of penalties against Lincoln, CES, and Silkman.  FERC sought this relief in Federal District Court after the subjects did not pay the penalties within the allotted 60 days.  The court may affirm, modify, or vacate FERC’s order, either in whole or in part.48 FERC’s enforcement action against Lincoln, CES, and Silkman, as well as its settlement with Rumford, illustrate the agency’s increased focus on market participants’ conduct in demand response programs in recent years.49

VI.          CFTC and Dodd-Frank Developments

The CFTC’s implementation of sweeping derivatives reforms under the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) continued forward in 2013.  Gary Gensler—the subject of both praise and consternation for his role as architect of many such reforms—stepped down as CFTC Chairman at the beginning of January 2014, but not before establishing, or sowing the seeds for, most of Dodd-Frank’s remaining major derivatives reforms.  Key Dodd-Frank developments in 2013 affecting energy companies are described below.

A.          Position Limits

The CFTC continued its initiative to establish federal speculative position limits, a key issue for many energy companies, by re-proposing in November 2013 position limits rules50 that in September 2012 had been vacated on procedural grounds by a federal court. The new proposal augments the previously provided rationales for the imposition of federal limits and is substantially similar to the vacated rules in prescribing spot-month and non-spot-month limits for 28 physical commodity agricultural, metal and energy futures contracts and their “economically equivalent” futures, options and swaps.  Like the vacated rules, the proposal would also exempt from the limits certain enumerated hedging positions upon submission of specified filings to the CFTC.  The CFTC also re-proposed aggregation rules51  which largely mirror (and in some cases provide greater flexibility than) earlier rules proposed in May 2012.  Some have criticized sharply the new proposed position limits and aggregation rules for not doing enough to minimize the obligations of commercial market participants, in particular, commercial hedgers.  It remains to be seen whether the CFTC will be receptive to such criticism if and when it adopts final position limits and aggregation rules.

B.          Cross-Border Guidance

In July 2013, the CFTC issued the much anticipated—and perhaps equally controversial—guidance52 on the cross-border application of Dodd-Frank’s swap provisions.  Among other U.S. end users, the guidance impacts energy companies with overseas affiliates.  The guidance is the culmination of a series of CFTC publications dating back to July 2012 on cross-border issues and, in general, describes the Dodd-Frank requirements that apply to swaps with one or more non-U.S. counterparties.  Notable issues addressed in the guidance include the definition of “U.S. person,” the application of the swap dealer and major swap participant thresholds and analysis and applicability of entity-level and transaction-level requirements to swaps with U.S. and non-U.S. persons, obligations of non-U.S. non-registrant end users and the availability of substituted compliance.  In December 2013, the CFTC issued comparability determinations making substituted compliance available for six jurisdictions, but these determinations were limited and did not cover key requirements such as mandatory clearing, mandatory trade execution or regulatory swap reporting.  Industry groups are seeking to invalidate the guidance on procedural grounds in federal court.53

C.          CFTC-FERC Memoranda of Understanding

On January 2, 2014, the CFTC and FERC (collectively, the agencies) signed “Memoranda of Understanding”54 regarding certain matters of overlapping jurisdiction (jurisdiction MOU) and sharing information in connection with market surveillance and enforcement activities (information sharing MOU, collectively, the MOUs). The MOUs came nearly three years after a statutory deadline, imposed by Section 720 of Dodd-Frank, for the agencies to negotiate such memoranda. The agencies had been operating under a 2005 Memorandum of Understanding generally providing for cooperation in enforcement matters but not explicitly recognizing the prospect of overlapping jurisdiction.

The agencies have sparred on jurisdiction over energy markets in recent years as their enforcement activities expanded.  In a federal appeals court, for example, the CFTC sided with the subject of a FERC enforcement investigation in challenging FERC’s authority to impose a $30 million civil penalty for alleged manipulation of the natural gas futures market.  The court held in March 2013 against FERC, reasoning that the CFTC has exclusive authority to police futures markets under the CEA.55 Some thought the court’s decision would encourage the agencies to issue the jurisdiction MOU soon after the ruling, but the agencies did not reach agreement on an MOU until the end of 2013, and ultimately avoided committing to any substantive positions in the jurisdiction MOU.

VII.          California Public Utilities Commission Energy Storage Mandate

In October 2013, the California Public Utilities Commission (CPUC) unanimously passed the United States’ first energy storage mandate.  The mandate requires the state’s largest three investor-owned utilities—Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company—to add 1.325 gigawatts of energy storage to their grids by 2020.  Three policy goals guided the target: (1) grid optimization, including reliability, peak reduction, and deferred transmission and distribution system upgrades; (2) integration of renewable energy; and (3) California’s goal of reducing greenhouse gas emissions to 80 per cent below 1990 levels by 2050.56

The mandate also prohibits utilities from owning more than 50 per cent of the storage projects they propose, with the goal of promoting merchant storage, customer-owned energy assets, and other arrangements that may be difficult to incorporate into current regulatory frameworks.57 To meet the 1.325 gigawatt target, the utilities must plan for energy loss during the energy storage process and the extra capacity required to cover those losses.

Under the mandate, the CPUC must judge the cost effectiveness of the energy storage plan, and the burden of proof rests on the owners.58   The CPUC will rely initially on energy storage evaluation software tools developed by the Electric Power Research Institute and utility consultancy DNV KEMA to make this determination.  The CPUC also will need to match emerging storage technologies, such as grid batteries, thermal energy systems, and microgrid projects, with correct market and regulatory mechanisms to measure their cost-effectiveness.

VIII.          Smart Grid and Privacy

In recent years, intelligence has been increasingly added to the U.S. grid through the deployment of advanced technologies and grid modernization efforts.  In turn, this increased intelligence has led to concerns regarding consumer privacy and security.  In January 2012, DOE’s Office of Electricity and Energy Reliability convened a workshop to facilitate a dialogue among key industry stakeholders regarding privacy and the fast-developing smart grid.  Thereafter, in February 2012, the White House issued Consumer Data Privacy in a Networked World: A Framework for Protecting Privacy and Promoting Innovation in the Global Digital Economy (White House Report).59 The White House Report outlined a multi-stakeholder process for developing legally enforceable voluntary codes of conduct to help instill consumer confidence that information is being protected, as well as a Consumer Privacy Bill of Rights.

DOE and the Federal Smart Grid Task Force then formed a group to facilitate a multi-stakeholder process to develop a voluntary code of conduct for utilities and third parties providing consumer energy use services that addresses privacy related to data enabled by smart grid technologies.  Thereafter, at its November 22, 2013 meeting, the Smart Grid Task Force proposed a mission statement intended to: (1) encourage innovation while appropriately protecting the privacy of consumer data and providing reliable, affordable electric and energy-related service; (2) provide customers with appropriate access to their own customer data; and (3) not infringe on or supersede any law, regulation, or governance by any applicable federal, state, or local regulatory authority.

The voluntary code of conduct addresses the following subject areas: (1) notice and awareness, (2) company management and customer redress, (3) choice and consent, (4) integrity and security, and (5) data access and participation. It was intended to be applicable to, and voluntarily adopted by, both utilities and third parties.  According to the mission statement, the intent is for utilities and third parties to consider adopting the voluntary code of conduct in its entirety, although exceptions may occur when state or local regulations indicate a different approach.  The mission statement notes that the voluntary code of conduct could be most beneficial to either entities that are not subject to regulation by applicable regulatory authorities or entities whose applicable regulatory authorities have not imposed relevant requirements.  A proposed final report is expected to be available in 2014.

IX.          Demand Response and Enhanced Measurement and Verification

The Energy Policy Act of 200560  requires FERC to prepare a report that assesses electric demand response resources and the penetration rate of advanced meters.  The Energy Independence and Security Act of 200761  builds on this requirement in directing FERC and DOE to perform a national assessment of demand response potential and develop a national action plan on demand response.

FERC has taken a number of actions to ensure that demand resources receive comparable treatment in jurisdictional transmission planning processes.  Among them is Order No. 890, which, among other things, requires that public utility transmission providers consider all types of resources, including demand response and energy efficiency, on a comparable basis in transmission planning.  Through its processing of compliance filings in response to its Order No. 1,000, FERC reaffirmed this Order No. 890 requirement.

FERC has also taken steps recently to ensure that demand response is competing on a level playing field with other resources.  In February 2013, FERC issued Order No. 676-G amending its regulations to incorporate by reference updated business practice standards adopted by the Wholesale Electric Quadrant of the North American Energy Standards Board to categorize various products and services for demand response and energy efficiency products offered in organized wholesale markets.  The standards require each RTO and ISO to address in its governing documents the performance evaluation methods to be used for demand response and energy efficiency products.62

A FERC staff report released in October 2013 summarized the new standards for energy efficiency adopted in Order No. 676-G.  The report stated that they provide criteria that will support the measurement and verification of energy efficiency products and services in organized wholesale electric markets as well as acceptable measurement and verification methodologies that energy efficiency resource providers may use.  The report further said they provide criteria for determining which type of baseline to use in various situations, such as the installation of new energy efficient equipment and processes or the replacement of outdated equipment. The standards also contain, according to the report, rules regarding the statistical methods used to accurately determine reduction values, specification for equipment used to perform measurements, and data validation.63  Finally, the report concluded that the standards will facilitate the ability of demand response and energy efficiency providers to participate in organized wholesale electric markets, reducing transaction cost and providing an opportunity for more customers to participate in such programs.64

X.          Energy Tax Credits

The production tax credit (PTC) for wind and other renewable energy technologies expired at the end of 2013.  However, pursuant to the American Taxpayer Relief Act of 2012 (enacted in January 2013), eligible projects that were “under construction” before January 1, 2014 were allowed to qualify for the PTC or for the energy investment tax credit in lieu of the PTC.  The Internal Revenue Service issued Notice 2013-29 in April 2013 and Notice 2013-60 in September 2013 addressing what it means for a project to qualify as “under construction,” and clarifying, among other things, that a change in ownership did not affect the project’s qualification for the tax credits.

On December 18, 2013, the Senate Finance Committee Chair, Max Baucus, D-Mont., released a discussion draft of legislation that would fundamentally change U.S. energy tax incentives.65  The U.S. tax laws contain over 40 energy related tax incentives, but well over half of these have short-term expiry dates, creating considerable uncertainty for investors and developers seeking to utilize these incentives.

Senator Baucus’ proposal would adopt two new nonrefundable tax credits for clean energy and clean transportation fuels.  Those credits, rather than requiring regular renewal, would be tied to national reductions in greenhouse gas intensity in U.S. electricity facilities and transportation fuels.  The credits would be available to facilities using all technologies as long as emissions standards are satisfied.

The credit would be available as either:

(1) a production tax credit of up to 2.3 cents per kilowatt-hour for energy or up to $1 per gallon for transportation fuel produced over a ten-year period; or (2) an investment tax credit (ITC) of up to 20 per cent of the cost of the facility producing energy or transportation fuels.  Notably, the new ITC would reduce the percentage of the cost of a facility that is eligible for the credit from 30 to 20 per cent.  Businesses could choose between claiming the credit as a PTC or ITC.  The new PTC and ITC would be available for at least a ten-year period, but would not be permanent.  Any facility producing electricity that is approximately 25 per cent cleaner than the average for all electricity production facilities would be eligible to receive the new PTC or ITC.  The principle that the proposal seeks to implement is: the “cleaner” the facility, the larger the credit.  The new PTC and ITC for energy facilities would not be available to facilities that are placed in service before January 1, 2017.  However, after 2016, the ITC could be claimed for existing facilities that undertake a carbon capture and sequestration retrofit that captures at least 50 per cent of carbon dioxide emissions.  The clean energy credits would phase out over a period of four years after the greenhouse gas intensity of U.S. electricity generation has declined to the point that it is 25 per cent cleaner than 2013 emissions.

Although Senator Baucus no longer chairs the Senate Finance Committee, it is expected that his successor, Senator Ron Wyden, D-Wash., will give the draft legislation careful consideration.

XI.          Gas-Electric Coordination

In 2013, FERC continued to be active in its efforts to identify opportunities to improve coordination between the natural gas and electricity industries.66 FERC focused primarily on the ability of such industries to communicate and share information, which it views as essential for the efficient operation of both industries.67  In July 2013, FERC issued a proposed rulemaking seeking comments on rule changes designed to foster “robust communication” between the industries “to ensure that both systems operate safely and effectively for the benefits of their customers.”68 In November, it adopted the proposed rules without modification.69 The final rule explicitly allows interstate natural gas pipelines and electric transmission operators to share non-public operational information to promote the reliability and integrity of their systems.70 To protect against undue discrimination and ensure the confidentiality of shared information, FERC approved a No-Conduit Rule that prohibits recipients of the information exchanged pursuant to the final rule from disclosing it to an affiliate or a third party.  The No-Conduit Rule does not affect current communications among interstate and intrastate natural gas pipelines, local distribution companies, and gatherers regarding conditions affecting gas flows between these physically interconnected parties, nor does it affect communications between transmission system operators and load serving entities.71   In response to comments, the Commission clarified that the final rule does not prohibit electric transmission operators from sharing non-public, operational information received from an interstate pipeline under the rule with a local distribution company, “if the information sharing and appropriate safeguards to prevent inappropriate use or disclosure of shared information is separately authorized by the Commission.”  As an example of a permissible disclosure, the Commission cited an ISO or RTO’s disclosure of information pursuant to a tariff filing under section 205 of the FPA.72

XII.          FERC Policy on Capacity Allocation for New Electric Transmission Projects

In January 2013, FERC issued a Final Policy Statement that clarified and refined its existing policies governing the allocation of capacity for new merchant transmission projects and new non-incumbent, cost-based, participant-funded transmission projects.73

Under the new policy, FERC now permits the following:

  • Merchant transmission developers’ selecting a subset of customers (not using unduly discriminatory or preferential criteria) and direct negotiation with those customers to reach agreement on rates, terms, and conditions;
  • Allocation of up to 100 per cent of transmission capacity through bilateral negotiations only after developers have (1) broadly solicited interest in the project from potential customers and (2) demonstrated compliance with the solicitation, selection, and negotiation process criteria; and
  • Allocation of capacity to affiliates when done in a transparent manner that adheres to certain protections, including open solicitation.

The Final Policy Statement did not change the four factors applied by FERC when it evaluates requests by merchant transmission developers for negotiated rate authority: (1) the justness and reasonableness of rates; (2) the potential for undue discrimination; (3) the potential for undue preferences, including affiliate preference; and (4) regional reliability and operational efficiency requirements.74  The Final Policy Statement did, however, modify how FERC analyzes the second and third factors.  The second and third factors will be deemed satisfied if transmission developers adhere to the guidelines set forth in the Final Policy Statement.

A.          Open Solicitation Process

Prior to negotiating with potential transmission customers, developers are required to engage in an open solicitation process in lieu of the previous requirement of a formal “open season.” To comply with the Final Policy Statement, developers should include a broad notice issued in a manner that ensures that all potential and interested customers are informed of the proposed project that includes sufficient technical information and the criteria the developer plans to use to select transmission customers (e.g., credit rating, “first mover” status, and customers’ willingness to incorporate project risk-sharing into their contracts).

B.          Post-Selection Demonstration

FERC continues to require merchant transmission developers to disclose the results of their capacity allocation process, though it will now be noticed and acted upon under section 205 of the FPA.  Developers are expected to demonstrate the fairness of their process by describing the criteria used to select customers, any price terms, and any risk-sharing terms and conditions that served as the basis for identifying transmission customers.

C.          Non-Incumbent, Cost-Based, Participant-Funded Projects

FERC announced that its Final Policy Statement also applies to new non-incumbent, cost-based, participant-funded transmission projects.  The Commission, however, acknowledged the differences between merchant transmission projects, and said it will review the transmission rate, terms and conditions, including any agreed upon return on equity, for non-incumbent, cost-based, participant-funded transmission projects more closely to ensure they satisfy precedent regarding cost-based transmission service.

D.          Incumbent, Cost-Based, Participant-Funded Projects

FERC also announced that it is not changing its case-by-case evaluation of requests for cost-based participant-funded transmission projects by incumbent transmission providers.  Incumbents were defined as those with a clearly defined set of existing obligations under their open access transmission tariffs with regard to new transmission development, including participation in regional planning processes and the processing of transmission service request queues.  Thus, the Final Policy Statement does not affect incumbent transmission development for the purpose of serving native load.

XIII.          Regulation of Ethane Pipelines

On December 31, 2013, FERC issued an order75  asserting jurisdiction over a proposed interstate ethane pipeline despite assurances that the ethane transported would be intended for non-energy, agricultural purposes. Although FERC’s jurisdiction over the Ethane Pipeline was an issue of first impression, the order’s reasoning may trump its holding in significance. FERC indicated that, going forward, it is likely to interpret its jurisdiction broadly based on the possible use of transported material rather than its intended, or even probable, use.

Williams Olefins Feedstock Pipelines, LLC (Williams) had petitioned FERC to disclaim jurisdiction over its planned Williams Bayou Ethane Pipeline (Ethane Pipeline).  Williams represented that the Ethane Pipeline would deliver unbatched purity liquid ethane to petrochemical plants and storage facilities in Texas and Louisiana.  Williams said the ethane would be used as feedstock to produce ethylene, not fuel.  On this basis, Williams asked FERC to assess the “unique character” of the Ethane Pipeline by applying what Williams claimed is FERC’s “traditional test” for jurisdiction: whether the product being transported serves an energy-related, as opposed to feedstock, function.

FERC rejected Williams’ request.  Describing Williams’ characterization of the jurisdiction test as “incomplete,” FERC articulated the governing test: whether the product being transported is a naturally-occurring hydrocarbon that is used or can be used for energy-related purposes, as opposed to having only a non-fuel, feedstock function.  FERC said ethane is a naturally-occurring hydrocarbon with a thermal heat content that can be used for fuel, and that it is commonly blended with low Btu natural gas to increase the Btu content to make such gas marketable as fuel.  FERC also noted that ethane has current energy uses and future undeveloped energy uses, as evidenced by companies’ submissions of proposals to expand LNG terminals to enable foreign export of certain propane.  FERC concluded these current and potential energy uses of ethane justified assertion of jurisdiction over the Ethane Pipeline.

FERC said it “will not disclaim jurisdiction over interstate ethane transportation based on an applicant’s assertion of the intended end-use of the ethane.”  FERC noted that the pipeline does not control the use of the transported products and that the use of such products can change. Given these realities, FERC said basing jurisdiction on intended end-uses of transported products could result in a “balkanized” pipeline system, with some pipelines regulated by FERC and others not.

XIV.          Pipeline and Hazardous Materials Safety Administration Safety Enforcement Rule

On September 25, 2013, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published a final rule amending its administrative procedures for the pipeline safety program.76  The amendments went into effect on October 25, 2013 and are intended to satisfy certain mandates in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pipeline Safety Act).77

The Pipeline Safety Act directed the PHMSA to issue regulations that (1) require hearings to be convened before a “presiding official;” (2) ensure the expedited review of corrective action orders in cases where a pipeline facility is deemed to be hazardous to life, property or the environment; (3) create a separation of functions between agency personnel who perform investigatory and prosecutorial duties and those who are responsible for deciding the final outcome of cases; and (4) prohibit ex parte communications with those decision-makers.78

The Pipeline Safety Act doubled the maximum civil penalties that the PHMSA can impose in federal enforcement actions to $200,000 per day79 and gave the PHMSA additional authority to enforce the onshore facility response plan requirements in the Oil Pollution Act of 1990.80

PHMSA’s final rule addressed each of these issues.  Among other things, it (1) established a new provision permitting imposition of administrative civil penalties on anyone who obstructs the conduct of a pipeline safety investigation or inspection; (2) specified the materials to be provided in the case file for an enforcement action; (3) implemented the Pipeline Safety Act’s mandates relating to the separation of functions and prohibitions on ex parte communications; (4) extended PHMSA’s enforcement proceedings to alleged violations of the onshore facility response plan requirements in the Oil Pollution Act of 1990; (5) defined the presiding official’s duties and powers; and (6) increased the maximum civil penalties for safety violations.81

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* Senior of Counsel at Morrison & Foerster LLP in Washington, D.C., where he represents a range of clients on energy regulatory, enforcement, compliance, transactional, commercial, legislative, and public policy matters.  He serves as Editor-in-Chief of the Energy Law Journal (published by the Energy Bar Association) and is a former General Counsel and Vice-President for Legislative and Regulatory Policy at Constellation Energy.  The author would like to thank members of Morrison & Foerster’s energy regulatory team for their assistance in developing this report.  The views expressed in this report are his own, and do not necessarily reflect those of Morrison & Foerster or any of its clients.

1 Robert S. Fleishman, “The Washington Report” Energy Regulation Quarterly (14 November 2013), online: <>.

2 Executive Office of the President, The President’s Climate Action Plan (June 2013), online: The White House Washington <>.

3 Office of the Press Secretary, Press Release, “President Barack Obama’s State of the Union Address” (28 January 2014), online: The White House <>.

4 Power Sector Carbon Pollution Standards, 78 Fed Reg 39533 (2013).

5 Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units, 77 Fed Reg 22392 (2012).

6 Ibid, 79 Fed Reg 1430 (2014).

7 See Rory Carroll & Nichola Groom, California Solar Plant Greeted with Fanfare, Doubts About Future (13 February 2014), online: Reuters <>.

8 See Mark Jaffe, 1st Auction of Solar Rights on Public Lands in Colorado Draws No Bids (24 October 2013), online: The Denver Post  <>.

9 See Bureau of Land Mgmt. Solar Energy Program, First‐In‐Line Pending and Authorized Solar ROW Applications on BLM‐Administered Lands as of November 1, 2013, online: BLM solar <>.

10 US Dep’t of Energy, Advanced Fossil Energy Projects Solicitation, online: Loan programs Office <>.

11 Energy Efficiency and Conservation Loan Program, 78 Fed Reg 73356 (2013).

12 Utility Air Regulatory group v Environmental Protection Agency, 684 F (3d) 102 (DC Cir 2012), No 12-1146 (US cert granted 15 October 2013).  Utility Air Regulatory Group is the lead case for 6 consolidated cases pertaining to the same issue.

13 Massachusetts v Environmental protection Agency, 549 US 497 (2007).

14 Prevention of Significant Deterioration and Title v Greenhouse Gas Tailoring Rule, 75 Fed Reg 31514 (2010).

15 See Adam Liptak, For the Supreme Court, a Case Poses a Puzzle on the E.P.A.’s Authority (24 February 2014), online: the New York Times <>.

16 E.g., Sean McLernon, Split High Court Presses Industry, EPA Over Carbon Rules (24 February 2014), online: Law360 <>; Mark Sherman, Supreme Court Seems Divided in Climate Case,  online: Associated Press <>.

17 US Dep’t of Energy, DOE/FE Order No 3357, Order Conditionally Granting Long-Term Multi-Contract Authorization to Export Liquefied Natural Gas by Vessel from the Freeport LNG Terminal on Quintana Island, Texas to Non-Free Trade Agreement Nations (15 November 2013), online: Office of Fossil Energy <>.

18 Letter from Sen. Ron Wyden and Sen. Lisa Murkowski to Ernest Moniz, U.S. Sec’y of Energy (2 August 2013), online: United States Senate <>.

19 Natural Gas Act , 15 USC §§ 3(a), 16, 717b, 717o (2013).

20 Energy Policy and Conservation Act of 1975 (EPCA), 42 USC § 6201 et seq (2013).

21 Letter from Paula A. Gant, Deputy Assistant Sec’y, Dep’t of Energy, to Sen. Lisa Murkowski (17 October 2013), online: United States Senate<>.

22 United States Environmental Protection Agency, Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: progress report (December 2012), online: EPA <>.

23 Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands, 78 Fed Reg 31635 (2013).

24 US, Bill HR 2728, Protecting States’ Rights to Promote American Energy Security Act, 113th Cong, (2013-2014).

25 Colo Rev Stat § 34-60-101 et seq (2013).

26  Cal Code Reg tit 14, § 1761 (2014), online: <>.

27 Ill Admin Code tit. 62 § 245 (2013).

28 For details regarding Norse Energy Corp. v Town of Dryden, 964 NYS.2d 714 (NY App Div 2013), currently pending before the Court of Appeals for New York, see the Fall 2013 issue of ERQ.

29 Robinson Township v Commonwealth of Pennsylvania, No 63 MAP 2012, 2013 WL 6687290 (Pa 2013)[Robinson Township].

30 58 Pa Cons Stat §§ 2301-3504.

31 Robinson Township, supra note 29 at 16.

32 Ibid at 33.

33 Ibid at 58.

34 The New Jersey decision is PPL EnergyPlus, LLC v Hanna, No 11-745, 2013 WL 5603896 (DNJ) (11October 2013) [Hanna].  The Maryland decision is PPL EnergyPlus, LLC, Nazarian, No MJG-12-1286, 2013 WL 5432346 (D Md) (30 September  2013) [Nazarian].  Appeals are pending in the US Courts of Appeals for the Third and Fourth Circuits, respectively.

35 Hanna, ibid at 36; Nazarian, ibid at 31.

36 Federal Energy Regulatory Commission, 2013 Report on Enforcement, FERC Docket No AD07-13-006 (21 November2013), online: FERC <>.

37 See 16 USC § 824v(a) (2012); 15 USC § 717c-1 (2012).

38 Barclays Bank PLC, 144 FERC ¶ 61041 (2013).

39 Notice of Motion and Motion to Dismiss, FERC v Barclays Bank PLC, No 2:13-cv-02093-TLN-DAD (ED Cal) (16 December  2013).

40 FERC filed a brief opposing Barclays’ and the individual traders’ motion to dismiss on February 14, 2014.  See Petitioner’s Opposition to Respondents’ Motion, FERC v Barclays Bank PLC, No 2:13-cv-02093-TLN-DAD (ED Cal) (14 February 2013).

41 In re Make-Whole Payments & Related Bidding Strategies, 144 FERC ¶ 61,068 (2013).

42 BP America Inc., 144 FERC ¶ 61,100 (2013).

43 Lincoln Paper & Tissue, LLC, 144 FERC ¶ 61,162 (2013); Competitive Energy Servs., LLC, 144 FERC ¶ 61,163 (2013); Richard Silkman, 144 FERC ¶ 61,164 (2013).

44 “Demand response” refers to a reduction in customers’ consumption of electricity from their anticipated consumption in response to an increase in the price of electricity or to incentive payments designed to induce lower electricity consumption.

45  “Baseline” is an estimate of a customer’s anticipated level of electricity consumption.  The baseline is used to measure the quantity of demand response (i.e., reduction of electrical consumption) delivered to the grid.

46 See Rumford Paper Co., 142 FERC ¶ 61,218 (2013).

47 Petition for an Order Affirming the Federal Energy Regulatory Commission’s August 29, 2013 Order Assessing Civil Penalty Against Lincoln Paper and Tissue, LLC, FERC v Lincoln Paper &Tissue, LLC, No 1:13-cv-13056-DPW (D Mass) (2 December  2013); Petition for an Order Affirming the Federal Energy Regulatory Commission’s August 29, 2013 Order Assessing Civil Penalty Against Richard Silkman and Competitive Energy Services, LLC, FERC v Silkman, No 1:13-cv-13054-DPW (D Mass)(2 December 2013).

48 Lincoln filed a motion to dismiss FERC’s petition on February 14, 2014.  See Lincoln Paper and Tissue, LLC’s Motion to Dismiss Complaint, FERC v Lincoln Paper & Tissue, LLC, Docket No 1:13-cv-13056-DPW (2 December 2013).  The motion argues, among other things, that FERC’s petition is time-barred by the applicable statute of limitations and that FERC lacks jurisdiction over demand response.  CES and Silkman also filed motions to dismiss.

49 See Enerwise Global Techs. Inc., 143 FERC ¶ 61,218 (2013) (settling allegations of market manipulation against demand response provider and imposing monetary penalties and remedies totaling approximately $1.3 million).

50 Position Limits for Derivatives, 78 Fed Reg 75680 (12 December 2013).

51 Aggregation of Positions, 78 Fed Reg 68946 (15 November 2013).

52 Interpretive Guidance and Policy Statement Regarding Compliance with Certain Swap Regulations, 78 Fed Reg 45292 (26 July  2013).

53 Complaint, Securities Indus. & Fin. Mkts. Ass’n v CFTC, No. 13-cv-1916 (DDC) (4 December  2013), ECF No 1.

54 Memorandum of Understanding between the Federal Energy Regulatory Commission and the Commodity Futures Trading Commission (2 January 2014), online:  FERC <>; Memorandum of Understanding between the Commodity Futures Trading Commission and the Federal Energy Regulatory Commission Regarding Information Sharing and Treatment of Proprietary Trading and Other Information (2 January 2014), online: FERC <>.

55 See Hunter v FERC, 711 F (3d) 155 (DC Cir 2013).

56 CPUC, Proposed Decision of Commissioner Peterman, Decision Adopting Energy Storage Procurement Framework and Design Program, App A (17 October 2013), online: CPUC <>.

57 Ibid at 33.

58 Ibid App A at 3, 7.

59 White House, Consumer Data Privacy in a Networked World: A Framework for Protecting Privacy and Promoting Innovation in the Global Digital Economy (23 February 2012), online: The White House <>.

60 Energy Policy Act of 2005, Pub L No 109-58, § 1252(e)(3), 119 Stat 594 at 966 (2005).

61 Energy Independence and Security Act of 2007, Pub L No 110-140, § 529, 121 Stat 1492, 1664 (2007) (to be codified at National Conservation Policy Act, 42 USC §§ 8241-8279).

62 Standards for Business Practices and Communication Protocols for Public Utilities, 142 FERC ¶ 61,131 at P 1(2013).

63 FERC Staff Report, Assessment of Demand Response & Advanced Metering  (October 2013), online: FERC <>.

64 Ibid at 2.

65 Max Baucus, Senate Committee on Finance, Energy Tax Reform Discussion Draft (18 December 2013), online: <>.

66 See generally Coordination between Natural Gas and Electricity Markets, FERC Docket No AD12-2-000.

67 See Order Directing Further Conferences and Reports, 141 FERC ¶ 61,125 (2012).

68 Communication of Operational Information between Natural Gas Pipelines and Electric Transmission Operators, 144 FERC ¶ 61,043 (2013).

69 Communication of Operational Information between Natural Gas Pipelines and Electric Transmission Operators, 145 FERC ¶  61,134 (2013), rehearing pending.

70 Ibid at paras 1, 2, 7.

71 Ibid at paras 7, 15, 16, 32 & n 27.

72 Ibid at para 56.

73 Allocation of Capacity on New Merchant Transmission Projects and New Cost-Based, Participant-Funded Transmission Projects, and Priority Rights to New Participant-Funded Transmission, 142 FERC ¶ 61,038 (2013).

74 See Chinook Power Transmission, LLC, 126 FERC ¶ 61,134 at 37 (2009).

75 Williams Olefins Feedstock Pipelines, LLC, 145 FERC ¶ 61,303 (2013).

76 Pipeline Safety: Administrative Procedures; Updates and Technical Corrections, 78 Fed Reg 58897 (2013) (codified at 49 CFR pts 190, 192, 193, 195, and 199).

77 Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, Pub L No 112-90, 125 Stat 1904 (codified at 49 USC §§ 60101-60138).

78 Ibid § 20, 125 Stat 1916.

79 Ibid § 2(a), 125 Stat 1905.

80 Ibid § 10, 125 Stat 1912.

81 See generally 78 Fed Reg 58897 at 58899-12.

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