Tag: energy

Business Owners Take Note as Enterprise Completes Its Mission: Supreme Court Holds No Common Law Partnership Was Formed with ETP

Logic is the beginning of wisdom, not the end.

— Dr. Spock, Star Trek, Starfleet Officer

The long running legal saga between Enterprise Products Partners (“Enterprise”) and Energy Transfer Partners (“ETP”) finally concluded on January 31, 2020, when the Texas Supreme Court unanimously decided that no partnership had ever arisen between the parties. (Read) This dispute between two of the major players in the energy industry focused on the legal standard for determining when a partnership is formed. ETP argued that the test should be based on the parties’ conduct, while Enterprise maintained that the parties had agreed that specific conditions in their contracts had to be established before a partnership was created, and those conditions were never met.

As the Supreme Court’s opinion brings to a close eight years of hard-fought litigation between Enterprise and ETP, we will share our third, and hopefully last, blog post about the case and also review some important lessons for business owners gleaned from this legal conflict. ¹

Predictable Legal Result

The staggering $535 million jury verdict that ETP secured against Enterprise in 2014 had always rested on tenuous legal ground because it conflicted with the terms of the parties’ written agreements. At trial, ETP claimed that Enterprise had breached its fiduciary duty as a partner when it ditched ETP to enter into a new pipeline deal with a competitor, Enbridge. The result at trial rested on the jury’s finding that the parties’ conduct had created a partnership between them, which gave rise to a duty of loyalty that was owed by Enterprise. The jury’s verdict, however, disregarded the parties’ written agreements, which set forth specific conditions precedent to the formation of a partnership, including approval by both companies’ boards. Enterprise therefore argued that it had become subject to a “partnership by ambush.”

The Texas Supreme Court has long championed the sanctity of contract. In numerous previous cases, the Court expressed the view that sophisticated business parties who enter into contracts must honor their bargain. Therefore, the Court’s decision on behalf of Enterprise was not surprising to Court watchers. In addition, a decision in ETP’s favor upholding its common law partnership claim would have created significant uncertainty in the business community as to when a partnership, and related partnership duties, would arise between contracting parties.

In its decision, the Court cited common law strongly favoring the freedom of contract, and held that parties can adopt conditions precedent that must be met before a partnership will be formed. The Court also cited language from a case it had decided more than a decade ago, and noted that: the Legislature did not “intend to spring surprise or accidental partnerships” on parties. While the Court acknowledged that the conditions precedent the parties agreed to could have been waived or modified, it held that ETP was required to either obtain a jury finding that the conditions had been waived or prove waiver conclusively at trial, and ETP had done neither. ²

Business Lessons Learned

While Enterprise ultimately prevailed in defeating ETP’s partnership claims, the legal battle required an enormous amount of time, caused considerable distraction and required each of the parties to incur millions of dollars in legal expense. Thus, the Court’s holding in ETP v. Enterprise provides some key take-aways for business owners. If the practices reviewed below are followed when parties are considering entering into a new business relationship, they may help to avoid future litigation. At a minimum, these practices will make it more likely that a court or an arbitration panel would grant a summary judgment dismissing before trial claims alleging that the parties entered formed a new partnership based on their conduct.

  • Get it clearly in writing — This is the clear guidance from the Supreme Court. If a party does not want to be saddled with partnership duties, it should confirm in writing that: (i) no partnership has been formed, and (ii) no partnership will be formed unless specifically stated conditions are met, e.g., the requirement that a written partnership agreement must be signed and approved by the company’s board and/or managers.
  • Address waiver — All agreements can be waived or modified, but the parties can expressly agree there will be no waiver or amending of any conditions to forming a partnership unless the waiver or amendment is signed and in writing;
  • Disclaim all fiduciary duties — In addition to making it clear that no partnership exists without specific conditions being met, the parties can also state that they do not owe each other any fiduciary duties unless and until they sign off on a binding written agreement between them;
  • Consider use of arbitration — The parties may require that all disputes arising between them will be decided by sophisticated business lawyers in an arbitration proceeding, and they can require that the arbitration hearing be held promptly, within 60 or 90 days;
  • Impose damage caps — The parties can agree to limit recoverable damages in a variety of days in any future dispute that arise between them, which can include their agreement to eliminate all claims for consequential damages, for lost profits and for punitive damages; and
  • Award fees to prevailing party — The parties can also award reasonable legal fees to the prevailing party, which will require the losing party to pay all of the legal fees that are incurred in the litigation or arbitration.

Conclusion

One man cannot summon the future. But one man can change the present!

Alternate Mr. Spock, “Mirror, Mirror”

The Supreme Court’s decision in the Enterprise case confirms the critical importance of securing written agreements that document the parties’ business relationship. Business owners who sign letters of intent, or enter into other preliminary documents before formally starting a new business relationship need to take care to ensure they are not forming a partnership or joint venture unless specific conditions are met. The failure to incorporate these conditions in a signed agreement may result in adverse consequences for the business owner, including being saddled with claims that a partnership was formed and that, as a result, they are now burdened with burdensome fiduciary duties.

¹ This post has a Star Trek reference based on the USS Enterprise, the name of the flagship in the show. As Star Trek fans know, the series was written in 1964, and first debuted on television in 1966. Perhaps it is a coincidence, but the first United States nuclear-powered aircraft carrier, the USS Enterprise, entered into service just a few years before, in 1962.

² In issuing its decision, the Supreme Court upheld the opinion of the Dallas Court of Appeals, which had overturned the trial court’s judgment. The appellate court had determined that ETP had not shown that it met the conditions precedent set forth in the parties’ agreements and, further, there was no jury finding these conditions had ever been waived or modified by the parties.

 

© 2020 Winstead PC.

ARTICLE BY Ladd Hirsch of Winstead.
For more on common-law partnerships see the National Law Review Corporate & Business Organizations Law section.

Predicting Old Man Winter and Energy Outlooks: Is it Anyone’s Guess?

Whether we have a strong winter impacts many things.  From our road conditions driving to work, the extent of demand for home heating fuels, how our livestock will fair, and our ski season (including vital tourist revenue that results from ski season), predicting the degree of the intensity of the winter season can be important.

But this year it looks like it could be anyone’s guess…some degree of certainty would be nice, as it can have a major impact on energy forecasts as well.  For example, natural gas and propane demand.

The U.S. Energy Information Administration (“EIA”) released its Short-Term Energy Outlook (“STEO”) earlier this month, which can be found here.  The October STEO contains a lot of interesting information, including, but not limited to, that the “EIA expects downward oil price pressure to emerge in the coming months as global oil inventories rise during the first half of 2020.”

However, what really caught my eye in the October STEO was the EIA’s prediction as to the upcoming winter.

In my neck of the woods, cattle ranchers are bracing for a big winter – folks are beefing up (pun intended) winter structures in their pastures to give their cows some protection from intense snow storms, and old timers are warning to push calving season later this year to avoid calves being born during the worst of the early spring snow storms.  Many people in my home state of Wyoming have already buttoned up their summer homes in the mountains and have had snowfall since the beginning of the month.  According to The Weather Channel article entitled, It’s a Record-Snowy Start For the Northern Rockies and Plains and Winter Is Still Over 2 Months Away, some areas have already been pounded by record-dumping snowstorms.

In fact, The Old Farmer’s Almanac similarly predicts in its winter 2019-2020 forecast, which can be found here, “below-normal winter temperatures” through most of the U.S. coupled with significant snowfall.  The 2020 Old Farmer’s Almanac predicts a “snow-verload” of “frequent snow events – from flurries to no fewer than seven big snowstorms coast to coast, including two in April for the Intermountain region west of the Rockies.”

The October STEO takes a different stance – The EIA forecast as to the winter fuels outlook is based upon a mild winter.  Indeed, the October STEO provides the following winter fuels outlook:

  • “The [EIA] forecasts that average household expenditures for all major home heating fuels will decrease this winter compared with the last.  This forecast largely reflects warmer expected winter temperatures compared with last winter.”

The National Oceanic and Atmospheric Administration (“NOAA”) also released the following prediction:  Winter Outlook: Warmer than average for many, wetter in the North, which forecasts “warmer-than-average temperatures…for much of the U.S. this winter.”  NOAA predicts that “[n]o part of the U.S. is favored to have below-average temperatures this winter.”

The Weather Channel seems to take the middle road in its forecast entitled, Winter 2019-20 Will Likely Be Warmer Than Average in Southern U.S. & Colder Than Average in Parts of Northern Tier, and also includes the following disclaimer: “Given some of the conflicting factors listed above, this forecast will likely change, so be sure to check back to weather.com for updates.”

What will this winter be like and what will the weather’s impact be on the domestic energy outlook?  It is anyone’s guess!

© Steptoe & Johnson PLLC. All Rights Reserved.

For more on the energy industry, see the National Law Review Environmental, Energy & Resources law page.

U.S. Department of Energy Withdraws Expanded General Service Lamp Definition and Refuses to Impose Backstop Efficiency Standard

On September 5, 2019, the U.S. Department of Energy (DOE) published a final rule and proposed rule regarding general service lamps and general service incandescent lamps with far-reaching implications for lamp manufacturers and retailers. DOE is withdrawing the Obama Administration’s revised definitions of general service lamps and general service incandescent lamps, which would have imposed federal efficiency standards on a wide array of lamps. DOE also asserts in the new rule that it has not triggered a statutory “backstop” efficiency standard, which would have prohibited the sale of all non-compliant lamps beginning January 1, 2020. In a separate proposed rule, DOE has initially determined that energy conservation standards for general service incandescent lamps are not justified. DOE’s decisions, which stall what was to be an accelerated transition away from incandescents and toward LEDs, will likely prompt a legal challenge by consumer and environmental groups, as well as a number of states and other interested stakeholders.

Background

As defined by Congress in the Energy Policy and Conservation Act of 1975 (EPCA), general service incandescent lamps (GSILs) are any “standard incandescent or halogen type lamp . . . intended for general service applications,” that “has a medium screw base,” that fits within statutorily defined lumen and operating voltage ranges, and that is not one of twenty-two exempted lamp types. General service lamps (GSLs), in turn, are GSILs or “any other lamps that the Secretary [of Energy] determines are used to satisfy lighting applications traditionally served by general service incandescent lamps.” With the Energy Independence and Security Act of 2007 (EISA), Congress directed DOE to initiate rulemaking procedures to determine whether efficiency standards for GSLs should be amended to be “more stringent” than those that currently apply to fluorescent lamps and incandescent reflector lamps and whether existing exemptions for “certain incandescent lamps should be maintained or discontinued.”

The EISA sought to prod DOE into moving quickly to establish GSL/GSIL efficiency standards. First, Congress provided that if DOE “determines that the standards in effect for general service incandescent lamps should be amended, the Secretary shall publish a final rule not later than” January 1, 2017. Second, Congress included a “backstop” measure: if the Secretary of Energy “fails to complete a rulemaking” as directed, “the Secretary shall prohibit the sale of any general service lamp that does not meet a minimum efficacy standard of 45 lumens per watt,” effective January 1, 2020. The 45-lumen standard is generally understood to be unachievable for many incandescents, and would, therefore, hasten an ongoing transition to LED lamps. The backstop standard is also unusual to the extent that it would apply as a prohibition on sale, while most other appliance and equipment standards enforced by DOE apply to import and manufacture, rather than sale. As a result, the backstop not only impacts lamp manufacturers, but also the retailers who market such lamps.

The Obama Administration in January 2017 promulgated final rules revising the GSL and GSIL definitions to no longer exempt five categories of specialty incandescent lamps (rough service lamps, shatter-resistant lamps, 3-way incandescent lamps, high lumen incandescent lamps, and vibration service lamps), incandescent reflector lamps, or a variety of decorative lamps (T-Shape, B, BA, CA, F, G16-1/2, G25, G30, S, M-14, and candelabra base lamps). Effective January 1, 2020, these lamp categories would be subject to the relevant efficiency standards. The Obama Administration, however, did not initiate rulemaking with regard to the efficiency standards themselves because an appropriations rider prevented it from doing so.

The Trump Administration’s recent move withdraws these revised definitions to maintain the current efficiency regulatory scheme. Without deciding whether or not to amend the efficiency standards themselves, DOE’s new rule prevents those standards from applying to the specialty, decorative, and reflector lamps identified under the earlier rule. Some commenters argue that the new rule violates the EPCA’s “anti-backsliding” provision, while DOE asserts that the provision applies only to efficiency standards and not to the categories to which those standards apply.

Regulatory Uncertainty Regarding “Backstop” Standards

With the new rule, DOE concludes that the backstop will not take effect on January 1 and so will not prohibit the sale of GSLs not meeting the 45 lumens per watt standard. DOE agreed with electrical and lighting trade associations and manufacturers that the backstop would only be triggered if DOE had actually determined to maintain, amend, or eliminate GSL and GSIL efficiency standards but failed to do so, whereas to date, DOE had determined only to maintain the currently effective list of exemptions from the GSL and GSIL definitions. Additionally, DOE states that the backstop is not self-executing but rather requires the Secretary to take action to prohibit the sale of less efficient lamps. DOE asserts that this interpretation of the backstop provision prevents the Secretary of Energy from having to enforce a more stringent efficiency standard that he has not yet determined to be necessary or unnecessary.

A variety of environmental commenters, utility companies, and state attorneys general disagree with DOE’s reading and argue that, without further action, the backstop provision will indeed be triggered on January 1, 2020, because DOE has “fail[ed] to complete” the congressionally directed rulemaking to determine the need for amended efficiency standards. These commenters argue that the backstop is self-executing and requires no further DOE action to go into effect.

Preemption

In recent years, states have begun to enact their own lamp efficiency standards in line with the Obama Administration’s proposal and Congress’ “backstop” standard, in part out of concern that DOE might seek to delay or reverse the federal standard. More states are likely to do so in light of DOE’s latest move, creating the possibility that lamp manufacturers, importers, and retailers will have to navigate a patchwork of state regulations. Such state regulations will likely be subject to litigation, as DOE asserts that even though it has not yet promulgated an efficiency standard, state standards for covered products are preempted.

Next Steps

DOE’s withdrawal of the revised GSL/GSIL definitions or its interpretation of the backstop provision has not yet prompted a legal challenge. Some environmental advocates, however, have raised the possibility of bringing suit to force implementation of the lamp efficiency standards.

 

© 2019 Beveridge & Diamond PC

ARTICLE BY Daniel A. Eisenberg and Jack Zietman of Beveridge & Diamond PC.

EPA Issues New Emergency Response Requirements for Community Water Systems

On March 27, 2019,  The Environmental Protection Agency (EPA) published the Federal Register Notice for New Risk Assessments and Emergency Response Plans for Community Water Systems describing the requirements and deadlines for community (drinking) water systems to develop or update risk and resilience assessments (RRAs) and emergency response plans (ERPs) under  America’s Water Infrastructure Act (AWIA) which was signed into law on October 23, 2018 and amends the Safe Drinking Water Act (SDWA).   Additionally, as described below, preparation of an ERP will enable owners or operators of community water systems to apply for grants from EPA for fiscal years 2020 and 2021.

Covered water systems.  Community water systems that serve more than 3,300 people are covered by these requirements. EPA interprets the population served to mean all persons served by the system directly or indirectly, including the population served by consecutive water systems, such as wholesalers.

Deadlines.  Each covered Community Water System completing an RRA and ERP must send certifications of completion by the dates listed below, and then review for necessary updates every 5 years thereafter:

Population Served by the Community Water System

Risk and Resilience Assessment (RRA) Certification

Emergency Response Plan (ERP)

The dates below are 6 months from the date of the RRA certification, based on a utility submitting a risk assessment on the final due date. Depending on actual RRA certification, ERP due dates could be sooner.

≥100,000

March 31, 2020

September 30, 2020

50,000-99,999

December 31, 2020

June 30, 2021

3,301-49,999

June 30, 2021

December 30, 2021

Risk and Resilience Assessment Requirements.  Each covered community water system must assess the risks to, and resilience of, its system including:

  • risk to the system from malevolent acts and natural hazards
  • resilience of the pipes and constructed conveyances, physical barriers, source water, water collection and intake, pretreatment, treatment, storage and distribution facilities;
  • electronic, computer, or other automated systems (including the security of such systems) which are utilized by the system;
  • monitoring practices of the system;
  • financial infrastructure of the system;
  • use, storage, or handling of various chemicals by the system; and
  • operation and maintenance of the system.

Emergency Response Plan Requirements (ERP). No later than six months after certifying completion of its risk and resilience assessment, each system must prepare or revise, where necessary, an emergency response plan that incorporates the findings of the assessment.  The ERP must include:

  • strategies and resources to improve the resilience of the system, including the physical security and cybersecurity of the system;
  • plans and procedures that can be implemented, and identification of equipment that can be utilized, in the event of a malevolent act or natural hazard that threatens the ability of the community water system to deliver safe drinking water;
  • actions, procedures, and equipment which can obviate or significantly lessen the impact of a malevolent act or natural hazard on the public health,  safety, and supply of drinking water provided to communities and individuals, including the development of alternative source water options, relocation of water intakes, and construction of flood protection barriers; and
  • strategies that can be used to aid in the detection of malevolent acts or natural hazards that threaten the security or resilience of the system.

The Federal Register Notice indicates that EPA is not requiring water systems to use any designated standards or methods to complete RRAs or ERPs, provided all of the requirements of the SDWA and AWIA are met.  AWIA already defines resilience and natural hazards. EPA will provide additional tools to foster compliance with its provisions and baseline information regarding malevolent acts no later than August 1, 2019.  With respect to the latter, it is anticipated that the agency will include consideration of acts that may (1) substantially disrupt the ability of the system to provide a safe and reliable supply of drinking water; or (2) otherwise present significant public health or economic concerns to the community served by the system.

Potential Impacts & Next Steps.  Preparation of an ERP will enable the owners or operators of community water systems to apply for grants under the Drinking Water Infrastructure Risk and Resilience Program, under which EPA may award grants in fiscal years 2020 and 2021.  If consistent with its ERP, a community water system may apply for grant funding for projects that increase resilience, such as:

  • Purchase and installation of equipment for detection of drinking water contaminants or malevolent acts;
  • Purchase and installation of fencing, gating, lighting, or security cameras;
  • Tamper-proofing of manhole covers, fire hydrants, and valve boxes;
  • Purchase and installation of improved treatment technologies and equipment to improve the resilience of the system;
  • Improvements to electronic, computer, financial, or other automated systems and remote systems;
  • Participation in training programs, and the purchase of training manuals and guidance materials relating to security and resilience;
  • Improvements in the use, storage, or handling of chemicals by the community water system;
  • Security screening of employees or contractor support services;
  • Equipment necessary to support emergency power or water supply, including standby and mobile sources; and
  • Development of alternative source water options, relocation of water intakes, and construction of flood protection barriers.

The EPA is currently developing a comprehensive training schedule, which will include both classroom and webinar options.

 

© 2019 Van Ness Feldman LLP.
Read more water infrastructure news on our environmental type of law page.

Sixth Circuit Compels Arbitration in Putative Class Action between Shell Oil and Ohio Landowners

Plaintiff entered into a lease agreement with Defendants (Shell Oil entities) governing extraction of oil and gas from his five-acre property located in Guernsey County, Ohio. The agreement provided a signing bonus to Plaintiff of $5,000 per acre, contingent upon Shell’s timely verification that he possessed good title to the property. The lease also contained a broad arbitration clause providing that any dispute under the lease was to be resolved by binding arbitration. Plaintiff brought suit, individually and on behalf of other landowners having similar contracts with Shell, for breach of contract after Shell allegedly failed to pay the signing bonus. The District Court for the Southern District of Ohio subsequently denied Shell’s motion to compel arbitration, and Shell appealed.

The Sixth Circuit reversed and remanded, compelling arbitration and a directing the district court to decide whether the lease allowed for class-wide arbitration. The panel found that the district court failed to address the threshold issue of who decides arbitrability and further reasoned that Plaintiff did not attack the enforceability of the “specific arbitration clause” but rather “argued that much of the contract, which happens to include the arbitration clause, is unenforceable.” In so finding, the panel determined that the arbitration clause was triggered at signing, leading to the applicability of the severability doctrine and the determination that an arbitrator must consider the issue first. As to the class-wide arbitration question, the Panel reasoned that because the parties did not identify a provision in the contract that clearly and unmistakably gave the arbitrator the power to decide the matter, and in light of “the importance of this issue to the case, given that the class could include hundreds of Ohio landowners,” that question would be for the district court to decide upon remand. In a dissenting opinion, Judge Moore opined that the district court was the proper body to decide whether the dispute should be arbitrated in light of the lease agreement’s two distinct triggering events – the signing of the agreement and the payment of the bonus. As such, Judge Moore opined that only after payment of the bonus would the arbitration clause apply.

Rogers v. Swepi LP, No. 18-3229 (6th Cir. Dec. 10, 2018).

 

©2011-2019 Carlton Fields Jorden Burt, P.A.
Read more about Oil and Gas lease agreements on the National Law Review’s Energy and Environment Page.

Colorado Supreme Court Vindicates the Colorado Oil and Gas Commission: Recent Ruling In Favor of the Oil and Gas Industry

In an important victory for Colorado’s oil and gas industry, the Colorado Supreme Court unanimously supported the decision of the Colorado Oil and Gas Conservation Commission (the “Commission”) to decline a rulemaking sought by environmental activists that could have eliminated new oil and gas drilling. The Commission, which has regulatory authority under the Colorado Oil and Gas Conservation Act, declined to act on a proposed rule that would have required oil and gas developers to prove that every future oil and gas development project, individually and cumulatively with other projects, had zero impact on the environment and public health, and would not contribute to climate change.

The Background

The Colorado Oil and Gas Conservation Commission v. Martinez case began in 2013 when environmental activists requested the Commission implement a rule that would have prohibited it from issuing any permits for the drilling of oil and gas wells “unless the best available science demonstrates, and an independent, third-party organization confirms, that drilling can occur in a manner that does not cumulatively, with other actions, impair Colorado’s atmosphere, water, wildlife, and land resources, does not adversely impact human health, and does not contribute to climate change.”

After holding extensive hearings on the proposed rule, the Commission ultimately declined to consider it given that the state statutes under which the Commission regulates oil and gas development require it to balance certain considerations with other factors, including the responsible development of Colorado’s oil and gas resources. The Commission was also addressing the activists’ concerns in conjunction with the Colorado Department of Public Health and Environment.

While a Colorado district court affirmed the Commission’s decision, a panel of the Colorado Court of Appeals reversed the district court’s order in a split decision based on Commission’s construction of the Colorado Oil and Gas Conservation Act.

The Decision

On January 14, 2019, the Colorado Supreme Court announced its decision in Colorado Oil and Gas Conservation Commission v. Martinez, 2019 CO 3, unanimously reversing the decision of the Court of Appeals, thereby affirming the Commission’s rejection of the proposed rule. The Supreme Court relied primarily on the language of the Colorado Oil and Gas Conservation Act, C.R.S. §34-60-101 et seq., which directs the Commission to foster the development of oil and gas resources, protecting and enforcing the rights of owners and producers, and in doing so, to prevent and mitigate significant adverse environmental impacts to the extent necessary to protect public health, safety, and welfare – but only after taking into consideration cost-effectiveness and technical feasibility.

In addition, the Supreme Court found support in the Colorado Oil and Gas Conservation Act’s statutory and legislative history. The Act’s statutory history was initially entirely pro-development and later evolved to include environmental considerations. The Court also considered the Act’s legislative history, particularly how sponsors of the latest amendments that added environmental factors to the Commission’s balancing explained the amendments were not intended to halt all oil and gas production – which the proposed rule would have likely done.

What it means for your business

The proposed rule in Martinez, if adopted and implemented, might have caused a complete shut-down of Colorado’s oil and gas industry. The Supreme Court’s affirmance of the Commission’s rejection of this proposed rulemaking establishes that Colorado’s courts will not presume to direct agencies to implement such potentially significant regulatory proposals, but will defer to the political process to make any such changes to the state’s regulatory landscape.

 

© Polsinelli PC, Polsinelli LLP in California
This post was written by Bennett L. Cohen, Ghislaine G. Torres Bruner Philip W. Bledsoe and Megan Rose Garnett of Polsinelli PC.
Read more oil and gas news on our Energy and Environment type of law page.

U.S. Court of Appeals for the Fourth Circuit’s Decision to Vacate Mountain Valley Pipeline Nationwide Permit

On November 27, 2018, the U.S. Court of Appeals for the Fourth Circuit issued the most recent in a series of decisions from various courts affecting the federal permitting and construction of interstate pipelines. Sierra Club v. U.S. Army Corps of Engineers, No. 18-1173 (4th Cir. Nov. 27, 2018). In this instance, the Circuit held that the U.S. Army Corps of Engineers violated the Clean Water Act when it verified that construction of the Mountain Valley Pipeline project could proceed pursuant to Nationwide Permit 12 in the State of West Virginia.[1] This decision will have an impact on the flexibility of federal and state agencies when it comes to permitting projects under the Clean Water Act Nationwide Permit program.

The Mountain Valley Pipeline project is a 304-mile natural gas pipeline proposed to run through West Virginia and Virginia. Earlier this year, the Corps had reinstated its verification that the project met the requirements of Nationwide Permit 12 – a general permit that provides authorization for certain discharges associated with the construction of linear energy infrastructure. The Circuit vacated the Corps’ verification in its entirety, leaving the project with no authorization under the Clean Water Act.

Unlike many decisions where the issue is the Corps’ own process in promulgating the Nationwide Permit in the first instance or the Corps’ assessment of whether a specific project falls within the federal parameters of the Nationwide Permit, this matter turned on whether the Corps properly incorporated the State’s conditions into its verification and whether the State itself followed the required Clean Water Act process.

In order to use a Nationwide Permit promulgated by the Corps, a project proponent must provide the Federal permitting agency a Section 401 water quality certification from the State (or other permitting agency with jurisdiction over the water) in which the regulated discharge originates, unless the Federal permitting agency determines that the certification requirement has been waived. The State certification and its conditions then become part of the federal Nationwide Permit. With respect to Nationwide Permit 12, the State of West Virginia had issued a general certification that imposed, after public notice and comment, certain special conditions on projects seeking authorization under Nationwide Permit 12 beyond what the Corps required. Two of these special conditions were at issue in this case:

  • Special Condition A, which requires an individual state water quality certification for certain projects including those involving construction of pipelines equal to or greater than 36 inches in diameter or if crossing waters regulated under Section 10 of the Rivers and Harbors Act; and

  • Special Condition C, which requires that individual stream crossings be completed in a continuous manner within 72 hours in certain conditions.

Pursuant to these Special Conditions, in order to seek authorization under Nationwide Permit 12, Mountain Valley Pipeline was expected to obtain an individual water quality certification and to complete stream crossings within 72 hours. However, West Virginia purported to “waive” its requirement that the pipeline obtain an individual water quality certification following a series of challenges to West Virginia’s individual water quality certification, and the Corps replaced Special Condition C with an alternate condition that the Corps found to be more protective of water quality with the apparent concurrence of the State.

The Fourth Circuit held: (1) the Corps’ verification violated Section 401 of the Clean Water Act because Section 401 unambiguously requires the Corps to incorporate the State’s certification with its special conditions in the federal verification without modification; and (2) Section 401 does not allow a state to waive its special conditions without public notice and comment, meaning that the project proponent remained subject to the condition requiring that it apply for an individual state water quality certification and, therefore, the Corps’ own verification was invalid.

In reaching these conclusions, the Circuit noted that “the Corps’ interpretation would radically empower it to unilaterally set aside state certification conditions as well as undermine the system of cooperative federalism upon which the Clean Water Act is premised.” Sierra Club, No. 18-1173 at *22. With respect to the State’s action purporting to waive its special condition, the Circuit explained that “[a]llowing West Virginia to revoke, on a case-specific basis, conditions imposed in its certification of a nationwide permit would impermissibly allow the state to circumvent [the CWA’s] explicit requirement that state permit certifications satisfy notice requirements.” Id. at *31.

Assuming this decision stands, the upshot is that both the Corps and the States (at least within the Fourth Circuit) will have less flexibility in how projects are permitted when a State has issued a general water quality certification with specific conditions. The Corps will need to require that the terms of such certifications are strictly followed in order to make decisions that comply with the Clean Water Act.

[1] The Circuit’s November 27, 2018 decision supports and expands upon the Circuit’s October 2, 2018 decision to vacate the Corps’ verification on more limited grounds.  Sierra Club v. U.S. Army Corps of Engineers, No. 18-1173 (4th Cir. Oct. 2, 2018).

© 2018 Bracewell LLP
This post was written by Ann D. Navaro and Christine G. Wyman of Bracewell LLP.

International Sanctions and the Energy Sector – Part 2: Russia

In the second part of this series we explore the EU and the US sanctions that have been imposed against the Russian energy sector.

RUSSIA

Background
The sanctions regimes against Russia were imposed in response to actual or alleged actions by the Russian government.  These included the annexation of Crimea and the destabilisation of Ukraine in 2014, plus the alleged malicious cyber activities aimed at interfering with or undermining the 2016 US presidential election.

They initially targeted a number of individuals and companies alleged to be involved in these actions or those close to the Russian government.  However, they have since been expanded to include sanctions prohibiting activity in certain sectors of Russia’s economy (in particular its energy industry) and have also targeted a number of the so-called ‘Oligarchs’ and the companies in their control.

More recently, sanctions have been imposed in the wake of the Novichok nerve agent attack in Salisbury, UK.

This article concentrates on the sanctions directly targeting the Russian energy sector.

The EU Sectoral Sanctions
The EU sanctions targeting the Russian energy sector are primarily contained in Council Regulation (EU) No 833/2014 (as amended) (the “EU Regulation”).  They seek to inhibit oil exploration and production projects in Russia:

  1. in waters deeper than 150 meters;
  2. in the offshore area north of the Arctic Circle; or
  3. which exploit shale formations by way of hydraulic fracturing.

(the “Targeted Projects”)

The sanctions operate in two key ways.  First, by preventing the sale, supply, transfer or export of the items listed in Annex II of the EU Regulation (which includes a number of items that can be used in the exploration or production of oil, for example, drill pipe and casing) by EU persons or from the EU for use in the Targeted Projects.1  Second, by prohibiting the direct or indirect provision of associated services necessary for the Targeted Projects, including: drilling, well testing, logging and completion services; and supply of specialised floating vessels.2

The EU Regulation also prohibits:

  1. certain dealings, directly or indirectly, with transferable securities and money-market instruments with a maturity exceeding 30 days and issued after 12 September 2014 by, or
  2. the making of loans or credit with a maturity over 30 days to,

certain Russian companies involved in the sale or transportation of crude oil or petroleum products, any non-EU subsidiaries owned 50% or more by them and any person acting on their behalf or at their direction.3  The companies currently listed in the EU Regulation are Rosneft, Transneft and Gazprom Neft.

Finally, the EU Regulation states that prior authorisation is required in respect of the provision of certain assistance or financing related to the items listed in Annex II of the EU Regulation to individuals or entities in Russia or if the items are to be used in Russia.4

A separate EU regulation prohibits the sale, supply, transfer or export of certain goods and technology suited for use in the energy sector and for the exploration of oil, gas and mineral resources to Crimea or Sevastopol and any associated assistance of financing.5

The EU sanctions apply to anyone within the EU, any EU national or company incorporated in the EU (wherever they may be physically located), and to any business done in whole or in part in the EU.

The US Sectoral Sanctions
The US sanctions targeting the Russian energy sector are primarily contained in Executive Order 13662 (as amended) (the “Order”) and in the Countering America’s Adversaries Through Sanctions Act (“CAATSA”).

The Order applies to “United States persons”.6  However, it could also apply to non-US persons in respect of any transaction that causes a US person to violate the Order or causes a violation of the Order to occur in the US.

In similar fashion to the EU Regulation, Directive 4 of the Order seeks to inhibit oil exploration and production from the Targeted Projects.  It does this by preventing goods, services (other than financial services), or technology in support of exploration or production from being provided to certain restricted entities and their 50% or more subsidiaries.

However, following the introduction of CAATSA in August 2017, the US sectoral sanctions went a step further than their EU counterparts.  In particular, CAATSA extended Directive 4 to include oil projects outside Russia in which the restricted Russian entities have a 33% or greater ownership interest or own the majority of the voting rights.  The US sectoral sanctions can therefore impact projects located far from Russian borders.

The Order also attacks the ability of key companies in the Russian energy sector to access the international debt markets.  Directive 2 of the Order prohibits new debt with a maturity of more than 60 days being issued to certain entities and their 50% or greater subsidiaries.

CAATSA contains various additional provisions impacting the Russian Energy Sector.  In particular, it provides for the:

  1. mandatory imposition of sanctions on non-US persons who knowingly7 make a significant investment8 in a project intended to extract crude oil from deepwater, Arctic offshore or shale projects in Russia (section 225); and
  2. discretionary imposition of sanctions on a person (not limited to US persons) who knowingly:
    1. makes an investment of $1 million or more (or an aggregate value of $5 million or more over a 12‑month period), which directly and significantly contributes to the enhancement of the ability of Russia to construct energy export pipelines; or
    2. provides goods, services, technology, information or support to Russia, which could directly and significantly facilitate the maintenance or expansion of the construction, modernisation or repair of energy export pipelines. (section 232)

That section 232 refers to “energy export pipelines” is significant.  Unlike the previous sanctions targeting the oil sector, section 232 could be applied to pipelines carrying Russian gas, large amounts of which are imported by the EU.

These additional provisions purport to have extraterritorial effect, which means they are of concern to non-US persons who are otherwise outside the US jurisdiction.  Any non-US persons breaching these provisions may become subject to secondary sanctions that would severely restrict their ability to do business with the US and to access the US financial system, and therefore the international financial system.

The Reaction of Energy Companies
The sanctions imposed on the Russian energy sector have received mixed reactions among energy companies.  The differences between the EU and US sanctions, most especially the manner in which they are enforced, has led to the perception that US companies are more affected than their European counterparts.

Mostly, however, energy companies have been able to progress their projects unimpeded by the sanctions.  This likely reflects the types of projects being progressed in Russia since the sanctions came into force.

The EU and US sectoral sanctions target oil exploration and production from deepwater, Arctic offshore or shale projects in Russia.  Such projects are complicated and require the adoption of advanced techniques and technologies.  Accordingly, they are typically more expensive than, for example, conventional shallow water or onshore drilling operations.  Projects of this nature therefore tend to be uneconomic in periods of lower oil prices, such as those experienced since 2014.  For these reasons, it is possible that such projects might not have been pursued since 2014 even in the absence of sanctions.

In fact, Russian oil production has increased from 10.86 million barrels per day in 2014 to 11.23 million barrels per day in 2017, making it the world’s third largest producer in 2017 behind the US and Saudi Arabia.9  This is a clear indication that the sanctions have not had a significant impact on the Russian energy sector’s ability to produce crude.

Looking Forward
It is questionable whether the sanctions imposed on Russia’s energy sector have been effective.  They have not, it seems, prevented Russia from increasing its production of oil.  Neither have they prevented all deepwater, Arctic or shale projects from being progressed.  However, with higher oil prices than when the sanctions first took effect, the economics of such projects should become more palatable and Russia may begin to feel the impact of the sanctions to greater extents.

Furthermore, the extraterritorial aspects of CAATSA are likely to begin affecting the appetite of non-US persons to make significant investments in Russian energy export pipelines or in Russian deepwater, Arctic offshore or shale projects.  There is also the risk of further sanctions.  The US Energy Secretary, Rick Perry, recently indicated that sanctions on the Nord Stream 2 pipeline are possible and that further energy‑related sanctions are planned.10   In addition, further sanctions on Russia in relation to the Novichok nerve agent attack in Salisbury, UK are expected, although it is not yet clear what form they will take and whether they will target Russia’s energy sector.11

In the first part of this three part series we considered the impact of President Trump’s decision to re-impose sanctions on Iran’s energy sector with effect from 5 November 2018.

________________________________________________________________

1 Article 3 of the EU Regulation.

2 Article 3a of the EU Regulation.

3 Articles 5(2) and 5(3) of the EU Regulation.

4 Article 4.3(a) of the EU Regulation.

5 Article 2(b) of Regulation EU No 692/2014.

6 United States persons is defined as “any United States citizen, permanent resident alien, entity organized under the laws of the United States or any jurisdiction within the United States (including foreign branches), or any person in the United States” (Section 6(c) of Executive Order 13662).

7 “Knowingly” for these purposes means a person who had actual knowledge, or who should have known, of the conduct, circumstance or result.

8Guidance from the US Department of State that whether or not an investment is “significant” will be determined on a case by case basis taking into account inter aliathe nature and magnitude of the investment and its relation and significance to the Russian Energy Sector.

9here.

10here.

11 here.

 

© 2018 Bracewell LLP
This post was written by Robert Meade and Joshua C. Zive of Bracewell LLP.

Congress Enacts Legislation to Promote New Hydropower Development

On October 23, 2018, President Trump signed into law the America’s Water Infrastructure Act of 2018 (AWIA), S. 3021, a comprehensive water resources bill that includes provisions specifically targeted to promote new hydropower development.  The AWIA includes a package of hydropower bills that were previously approved by the U.S. House or Senate.  These include bills to promote new hydropower development at non-powered dams, new closed-loop pumped storage hydropower, new hydropower at qualifying conduit facilities, as well as longer preliminary permit terms and start of construction deadlines for new projects.  The legislation also provides incentives for redevelopment and modernization at existing projects during the license term.

BACKGROUND

Each individual bill that comprises the AWIA has been pending before Congress in one form or another for several years.  Certain of these provisions were included in the comprehensive energy bill that failed to pass at the end of 2016.  Since then, the bills have each been individually reintroduced before Congress and followed individual tracks.  They were only recently combined into the AWIA bill.  The bill passed the Senate by unanimous consent on September 4, 2018.  It passed the House by a vote of 99-1 on October 10, 2018, with Congressman Mike Lee of Utah as the sole dissenting vote.

THE AWIA

The AWIA is composed of five major categories of hydropower reform: (1) extending preliminary permit terms and start of construction deadlines for new construction projects; (2) promoting new, small conduit hydropower facilities; (3) promoting hydropower development at existing nonpowered dams; (4) promoting development of closed-loop pumped storage projects; and (5) incentivizing investments and modernization projects at existing hydropower facilities.

First, the AWIA amends the Federal Power Act (FPA) to authorize the Federal Energy Regulatory Commission (FERC) to issue preliminary permits for up to four years, instead of the previous three-year limit.  The legislation also authorizes FERC to extend a preliminary permit once for no more than four years, as opposed to the previous two years.  This increases the total possible preliminary permit term from the current limit of five years to a possible eight years.  The AWIA also codifies FERC’s current practice of issuing a new preliminary permit after the expiration of a permit under extraordinary circumstances.  With regard to newly licensed projects, the AWIA authorizes FERC to extend the time a licensee has to commence construction under a license for up to eight years beyond the two years allotted under the license.  Prior to enactment of the AWIA, FERC could extend the license once for no more than two years.  This increases the total possible time to commence construction of a newly licensed project from four years to 10.  These changes should facilitate developers’ ability to take projects from feasibility investigation to project completion without the recurring fear of expiring permits and frequent need for special legislation to extend license construction deadlines.

The AWIA also amends FERC’s current policy on the collection of annual charges for new projects.  Under current regulations, private licensees of unconstructed projects must begin paying annual charges on the date by which they are required to commence construction, or if that deadline is extended, no later than four years after the issuance date of the license (i.e., no later than four years after license issuance).  The legislation changes this policy to provide that annual charges for unconstructed projects commence at the later of (1) the date by which the licensee is required to commence construction, or (2) the date of any extension of the construction commencement deadline.  Because FERC is now authorized under the AWIA to extend the commence construction deadline for up to eight years, this provision of the legislation delays the start of annual charges up to 10 years after license issuance.  These provisions of the AWIA do not distinguish between private licensees and state and municipal licensees, who under current regulations are not required to start paying annual charges until the commencement of project operations.  However, the language appears to permit commencement of annual charges at a later date, allowing FERC to preserve its current regulations on the timing of annual charges paid by state and municipal licensees.

Second, the AWIA directs FERC to issue a rule establishing an expedited process for licensing non-federal hydropower projects at certain existing nonpowered dams.  In establishing this expedited process, the legislation requires FERC to convene an interagency task force with appropriate federal and state agencies and Indian tribes to establish licensing procedures that, to the extent practicable, ensure that such projects will not result in any material change to the storage, release, or flow operations of the nonpowered dam.  This appears aimed at ensuring, if possible, that federal licensing will not result in impairment of dams for their existing nonpower purposes such as irrigation and water supply.  Qualifying projects must not have been previously authorized for hydropower and must use for generation the withdrawals, diversions, releases, or flows from an existing dam, dike, embankment, or other barrier that is or was operated for the control, release, or distribution of water for agricultural, municipal, navigational, industrial, commercial, environmental, recreational, aesthetic, drinking water, or flood control purposes.  Qualifying projects also must not propose to materially change the operations of the nonpowered dam.  The expedited licensing process would result in an order not later than two years after receipt of a completed license application.  The AWIA also directs FERC and the Secretaries of the Army, the Interior, and Agriculture, within 12 months, to develop a list of existing nonpowered federal dams with the greatest potential for non-federal hydropower development.  The Secretary must provide the list to Congress and make it available to the public.

Third, the AWIA directs FERC to issue a rule establishing an expedited process for licensing closed-loop pumped storage projects.  Like the provisions for expedited licensing of projects at existing nonpowered dams, the legislation requires FERC to convene an interagency task force to coordinate the regulatory authorizations required to construct and operate closed-loop pumped storage projects.  Although leaving to FERC to develop a definition for “closed-loop pumped storage,” qualifying pumped storage projects must cause little to no change to existing surface and groundwater flows and uses and be unlikely to adversely affect species listed as threatened or endangered under the Endangered Species Act.  This would appear to narrow the class of qualifying projects considerably.  An expedited licensing process would result in an order not later than two years after receipt of a completed license application.  The AWIA also directs FERC to hold a workshop to explore potential opportunities for development of closed-loop pumped storage projects at abandoned mine sites and provide guidance to assist applicants for such projects.

Fourth, the AWIA amends the FPA with respect to the criteria and process to qualify as a qualifying conduit hydropower facility.  Under the 2013 Hydropower Regulatory Efficiency Act, certain hydropower facilities located on non-federally owned conduits with installed capacity of up to 5 megawatts (MW) are not required to be licensed or exempted by FERC.  The AWIA increases the size limitation to 40 MW for such facilities.  It also reduces the time for FERC to make a qualifying conduit determination decision from 45 to 30 days after an entity files a notice of intent to construct such a facility.

Fifth, the AWIA directs FERC, when determining the term of a new license for an existing project, to give equal weight to project-related investments by the licensee under the existing license, including rehabilitation or replacement of major equipment, and investments proposed under the new license.  This is a modification to FERC’s license term policy issued in 2017, which exempts all “maintenance measures” from consideration toward a new license term.  The AWIA allows a licensee to seek a determination from FERC, within 60 days, on whether any planned, ongoing, or completed investment would be considered by FERC in determining a new license term.

IMPLICATIONS

The hydropower provisions included in the AWIA bill are a meaningful first step in modernizing the hydropower licensing process.  They are intended to generate renewed interest in new hydropower by allowing licensees more time and certainty to secure required approvals and financing for new projects, which was a challenging feat under current deadlines.  While the majority of the provisions in the AWIA are intended to promote new hydropower development, Congress also sought to promote major modernization and rehabilitation projects at existing hydropower projects by ensuring that the investments in such projects are rewarded in the term of a new license.

The AWIA does not include a number of other hydropower relicensing reforms that were included in the bipartisan Senate energy bill in 2016.  These include provisions: (1) designating FERC as lead agency for coordinating federal authorizations from all agencies needed to develop a project; (2) authorizing FERC to refer agency disputes to the Council on Environmental Quality; (3) requiring resource agencies to give equal consideration to developmental and non-developmental values when imposing mandatory conditions or prescriptions; and (4) expanding the definition of renewable energy for federal programs to include all forms of hydropower.  Unless these reforms are passed in the lame duck session, they must be reconsidered in the new 116th Congress beginning in 2019.

 

© 2018 Van Ness Feldman LLP
This post was written by Sharon White and Michael A. Swiger of Van Ness Feldman LLP.

EPA Proposes Affordable Clean Energy Rule

On August 21, 2018, the Environmental Protection Agency (EPA) issued a proposed rule pursuant to section 111(d) of the Clean Air Act (CAA) that would establish emission guidelines for states to develop plans to limit carbon dioxide (CO2) emissions from existing fossil-fired power plants.  The proposed Affordable Clean Energy (ACE) rule would replace the 2015 Clean Power Plan (CPP), which EPA is proposing to repeal (in a separate rulemaking) on the grounds that the CPP exceeded the agency’s authority under the CAA.

Core elements of the proposed ACE rule include: (1) a determination of the best system of emission reduction (BSER) for CO2 emissions from coal-fired power plants; (2) a list of “candidate technologies” states can use when setting CO2 performance standards for affected plants; (3) a new preliminary applicability test for determining whether a physical or operational change made to a power plant may be a “major modification” triggering New Source Review (NSR); and (4) new implementing regulations for establishing emission guidelines under CAA section 111(d).

Section 111(d)

EPA is proposing the ACE rule pursuant to section 111(d) of the CAA.  This section directs EPA to promulgate regulations establishing a federal-state process for setting standards of performance limiting emissions from existing sources for pollutants not otherwise regulated in other specified sections of the CAA.  Implementing section 111(d) is a three-step process.  First, EPA issues a “guideline” for states to use in developing compliance plans that include standards of performance for stationary sources within a particular source category.  The guideline identifies what EPA determines is the BSER for the relevant sources within the source category.  Second, each state submits a plan to EPA that includes standards of performance for the covered sources in the state.  Third, EPA approves or disapproves of the state plans.  If a state fails to submit an approvable plan, the CAA requires EPA to impose a federal plan.

Proposed BSER Determination

EPA is proposing to define BSER for CO2 emissions from existing coal-fired power plants as heat-rate efficiency improvements based on a range of “candidate technologies.”  This “inside the fence” BSER determination reflects a different approach than what was used in the CPP.  The CPP determined the BSER for power plants based on reductions achievable not only through inside-the-fence measures such as heat rate improvements but also through shifting of generation from higher-emitting to lower-emitting or zero-emitting plants.  As noted above, EPA has proposed to find that such an “outside-the-fence” approach to determining BSER exceeds the agency’s authority under the CAA.

EPA has identified a list of the “most impactful” heat rate improvement measures.  EPA is proposing that this list serve as the “candidate technologies” or “checklist” of BSER technologies, equipment upgrades, and best operating and maintenance practices for coal-fired power plants.  These candidate technologies are:

  • Neural Network/Intelligent Sootblowers

  • Boiler Feed Pumps

  • Air Heater and Duct Leakage Control

  • Variable Frequency Drives

  • Blade Path Upgrade (Steam Turbine)

  • Redesign/Replace Economizer

  • Improved Operating and Maintenance Practices

States would consider the above technologies in establishing standards of performance for existing coal-fired power plants.  EPA is proposing that performance standards will set a specific allowable emission rate expressed on a pound CO2 per MWH-gross rate for each affected unit based on the application of the appropriate candidate BSER technologies to each unit.

EPA explains in the proposed rule that it does not have sufficient information to make a BSER determination with respect to heat rate improvements at natural gas-fired simple‑cycle turbines or combined cycle turbines.  The agency is soliciting comment on this issue.  Previously, EPA determined that heat rate improvement measures at natural gas‑fired combustion turbines would not be considered BSER because such measures cannot provide meaningful reductions at reasonable cost.

State Compliance Plans

The proposed rule would provide each state with broad discretion in establishing specific performance standards for particular plants.  The proposal also allows state plans to rely on emission averaging and trading among affected coal‑fired units at a particular plant.  However, EPA has proposed that state plans should not be allowed to incorporate averaging and trading among different plants, such as a state-wide or interstate cap-and-trade program.  Nor will any credit be given for CO2 emissions reductions achieved through increased generation of renewable energy or gas-fired generation not covered under the section 111(d) regulatory program.  The proposed rule explains that such an approach would be inconsistent with EPA’s proposed “inside-the-fence” interpretation of BSER under section 111.

Permitting Under NSR Program

EPA is proposing revisions to the NSR permitting program to make it easier for power plants to adopt heat rate improvements without triggering NSR obligations.  The NSR program is a preconstruction permitting program.  An NSR permit is required not only before construction of a new major stationary source; it is also required before modifying an existing major source if the modification will result in a significant emissions increase of any NSR-regulated pollutant.  Projects that cause a significant increase in annual emissions may trigger onerous NSR permitting requirements, which include installation of state-of-art emission control technologies, prescriptive air quality modeling, and extensive public notice and comment procedures.

To avoid widespread triggering of NSR permitting requirements from heat rate improvement projects undertaken by affected coal‑fired plants, EPA is proposing to amend the NSR regulations to include an hourly emissions increase test.  Under the proposed revisions, a non-excluded physical or operational change to an electricity generating unit would only trigger NSR if the change resulted in an increase in the unit’s maximum hourly emissions rate under procedures proposed in the ACE rule, as well as a significant emission increase in annual emissions under the current NSR regulations.

As drafted, the proposed maximum hourly emission increase test would be available to any electricity generating unit, including natural gas-fired units that would not be subject to regulation under section 111(d).

States with approved NSR programs would have the option but would not be required to adopt the hourly emission increase test ultimately promulgated as part of the NSR provisions in their SIPs.  For those states with delegated NSR programs that are acting on behalf of EPA, the NSR permitting process would have to include any changes that are ultimately made to the federal NSR provisions as they would be administering the federal program.

EPA is proposing that the potential revisions to the NSR permitting program are severable from the rest of the ACE rule.

Implementing Regulations for Emission Guidelines under Section 111(d)

The proposal revises the general implementing regulations for section 111(d) that govern how EPA issues emission guidelines, and how and when states develop and submit their plans.  These changes would apply for all future section 111(d) rules.  Proposed changes include the following:

  • Timing:  The proposal updates timing requirements regarding submission of state plans and EPA action on those state plans.

    • State submissions:  EPA is proposing to provide states three years to develop state plans.  The existing implementing regulations provide nine months.

    • EPA action:  The proposal would allow EPA 12 months to act on a complete state plan submittal.  The existing implementing regulations provide four months.

    • Federal plan:  The proposal would allow EPA two years to issue a federal plan after a finding of a state’s failure to submit an approvable plan.  The existing implementing regulations provide six months.

  • Criteria for state plans:  The proposal has completeness criteria for state plans that include administrative materials and technical support for state implementation of the plan.  EPA would have six months to determine completeness and would make that determination by comparing the state’s submission against the completeness criteria.

  • Variance provisions:  The proposal provides greater flexibility to states to adopt plans that include variances from the EPA guidelines that will allow, among other things, states to take into account the remaining useful life of the unit and other relevant factors in establishing a performance standard for a particular affected unit.

Next Steps

EPA will take comment on the proposal for 60 days after publication in the Federal Register and will hold at least one public hearing.  Depending on the exact date of Federal Register publication, this means comments will be due to EPA sometime in late October 2018.

Impacts of EPA Proposal

According to EPA, the proposed ACE rule would reduce the compliance burden by up to $400 million per year when compared to the CPP.  EPA estimates that the ACE rule could reduce overall 2030 CO2 emissions by up to 1.5% from projected levels without the CPP.

 

© 2018 Van Ness Feldman LLP
This post was written by Kyle W. Danish and Stephen C. Fotis  of Van Ness Feldman LLP.