FERC Issues Final Rules to Revise Regulations to Confirm with the FPA’s Recent Changes

FERC Issues Final Rules to Revise Regulations to Confirm with the FPA’s Recent Changes

On February 21, the Federal Energy Regulatory Commission (FERC) issued two final rules revising regulations in order to conform to recent changes made by Congress to the Federal Power Act (FPA), in relation to FERC’s review of hydropower permits and public utility mergers.

The rule related to mergers “implements statutory changes to FPA section 203 by amending FERC regulations requiring a public utility to seek authorization to merge or consolidate jurisdictional facilities so that such authorization is required only when those facilities are valued at more than $10 million.”

These revisions will also require public utility companies to tell FERC about “mergers or consolidations if the facilities are valued at more than $1 million but less than $10 million.” It will also “reduce the regulatory burden on utilities for lower-value transactions, and the final action comes within the 180-day period set by Congress.”

The rule about hydropower “conforms the Commission’s regulations to the America’s Water Infrastructure Act of 2018, which amended sections of the FPA related to preliminary permits, qualifying conduit hydropower facilities, and start for payment of annual charges. Under the Act and the Commission’s amended rules, FERC can issue preliminary permits for four years and extend a permit once for an additional four years, instead of three-year terms for preliminary permits with a possible two-year extension.”

This rule also now allows FERC to “issue a second four-year extension if warranted by extraordinary circumstances.” FERC also increased the “maximum installed capacity for qualifying conduit exemptions is increased from five megawatts (MW) to 40 MW.”

FERC was authorized by the Act to “to issue extensions of the start of construction deadline for licenses for up to eight years, which affects the start of the payment of annual charges … Annual charges will begin two years after a license is issued or any extension deadline expires.”

The third rule FERC issued was to clarify and update the “requirements related to interlocking officers and directors.” FERC’s position on “late-filed applications and informational reports” was also clarified.

FERC Clarifies Reforms of Generator Interconnection Procedures and Agreements

FERC Clarifies Reforms of Generator Interconnection Procedures and Agreements

The Federal Energy Regulatory Commission (FERC) clarified its position on Order 845 on February 21. “Order No. 845 adopted ten reforms to improve certainty for interconnection customers, promote more informed interconnection decisions, and enhance the interconnection process.”

FERC received 12 requests for a rehearing or clarification on Order 845. “The draft order grants in part and denies in part the requests for rehearing and clarification.” While most of the reforms in 845 will remain unchanged, FERC granted the rehearing for some of the reforms. The rehearing was granted to clarify “two aspects of the reform to remove a limitation on the interconnection customer’s option to build.”

The Order requires “transmission providers [to] explain why they do not consider a specific network upgrade to be a standalone network upgrade, and second, allows transmission providers to recover option to build oversight costs.” It also clarifies two different parts of the “option to build reform by finding, first, that the Order No. 845 option to build provisions apply to all public utility transmission providers, including those that reimburse interconnection customers for network upgrades, and second, that the option to build does not apply to stand alone network upgrades on affected systems.”

The rehearing also covered reforms to “create a surplus interconnection service process,” explaining that FERC has no intentions to “limit the ability of RTOs and ISOs to argue that an independent entity variation is appropriate.”

There were clarifications regarding the “study model and assumption transparency.” It found that:

  • “Transmission providers may use the Commission’s critical energy/electric infrastructure information regulations as a model for evaluating entities that request network model information and assumptions.”
  • “The phrase ‘current system conditions’ does not require transmission providers to maintain network models that reflect current real-time operating conditions of the transmission provider’s system but should reflect the system conditions currently used in interconnection studies.”

They also clarified the reforms to “institute interconnection study deadline reporting requirements.” Another clarification was on “the date for measuring study performance metrics and clarifies that the reporting requirements do not require transmission providers to post 2017 interconnection study metrics. Instead, the first required report will be for the first quarter of 2020.”

As for the reforms on “requesting interconnection service below generating facility capacity,” a partial rehearing was granted “to find that an interconnection customer may propose control technologies at any time at which it is permitted to request interconnection service below generating facility capacity.”

They also addressed “the reform that allows interconnection customers to request interconnection service below generating facility capacity,” clarifying that transmission providers “must provide a detailed explanation if it determines additional studies at the full generating facility capacity are necessary when the interconnection customer has requested service below full generating facility capacity.”

The draft order denied other requests for rehearings or clarification.

The draft order will go into effect 75 days after it is published in the Federal Register. Public utility transmission providers have to “submit a single compliance filing, within 90 days of the issuance of this order, to comply with Order No. 845 and this draft order on rehearing and clarification.”

Federal Energy Regulatory Commission (FERC) Chairman Neil Chatterjee testified before the Senate Energy & Natural Resources Committee

Federal Energy Regulatory Commission (FERC) Chairman Neil Chatterjee testified before the Senate Energy & Natural Resources Committee

On February 14, the  Federal Energy Regulatory Commission (FERC) Chairman Neil Chatterjee testified before the Senate Energy & Natural Resources Committee to discuss cybersecurity in the energy industry. Chatterjee had three specific points to bring up in his testimony: “first, the evolution of mandatory reliability standards; second, the voluntary partnerships FERC has established with industry and other agencies; and third, the interdependency of the electric and natural gas systems.”

For the mandatory reliability standards, Chatterjee discussed the ruling under the Federal Power Act that gave FERC “authority to approve mandatory reliability standards developed by the North American Electric Reliability Corporation (NERC).” After these are approved, they become mandatory and either NERC or FERC enforces them. “NERC’s standards for cybersecurity, known as the Critical Infrastructure Protection (CIP) standards, became mandatory and enforceable in 2009.”

In the last ten years, “the CIP standards have matured considerably and now form an effective framework for protections against cyber threats,” Chatterjee said. As a result of the standards maturing, “the need for constant revisions to address discrete issues and, instead, has allowed both FERC and NERC to focus on tackling emerging threats.”  Chatterjee brought up two recent actions that FERC has taken in regard to this. “First, at our October 2018 Commission Meeting, FERC approved NERC’s proposed reliability standards to address supply chain threats. This action is particularly significant given that these specific threats to the energy sector continue to grow. Second, at our July 2018 Commission Meeting, FERC approved a final rule directing NERC to expand reporting requirements for critical systems.”

Chatterjee said the final ruling “directed NERC to develop a standard that requires registered entities to report successful and attempted intrusions into critical systems to NERC’s Electricity Information Sharing and Analysis Center, as well as to the Department of Homeland Security.” The Chairman said this was “an important step toward enhancing the collection and distribution of information on rapidly evolving threats.”

As for voluntary partnerships, Chatterjee said that even though the CIP standards are an “important baseline for cybersecurity practices,” merely complying “is not enough to achieve cybersecurity excellence.” FERC has developed “two-prong approach to address threats to energy infrastructure: mandatory reliability standards overseen by our Office of Electric Reliability, and voluntary initiatives overseen by our Office of Energy Infrastructure Security (OEIS).” OEIS works with partners in state and federal agencies as well as those in the industry “to develop and promote best practices for critical infrastructure security. These initiatives include … voluntary architecture assessments of interested entities, classified briefings for state and industry officials, and joint security programs with other government agencies and industry.”

Chatterjee wants to continue strengthening those partnerships, and in the spirit of that, FERC is holding a joint technical conference with the Department of Energy on March 28. “The conference will explore current threats against energy infrastructure, best practices for mitigation, current incentives for investing in physical and cybersecurity protections, and cost recovery practices at both the state and federal level.”

As for the interdependency of the electric and natural gas systems, Chatterjee expressed his concerns that “because of our nation’s growing use of natural gas for power generation, a successful cyberattack on the natural gas pipeline system could have a significant impact on the electric grid.”

“I recently met with TSA Administrator David Pekoske to discuss pipeline cybersecurity and was impressed by his focus on this vital issue as well as his pledge to taking further action to improve TSA’s oversight of pipeline security. While I think both industry and government have made significant strides toward addressing this issue, I believe more work still needs to be done, and the Commission stands ready to assist in these efforts.”

A full video of Chatterjee’s testimony can be viewed here.

FERC’s Energy Infrastructure Update for December 2018

FERC’s Energy Infrastructure Update for December 2018

On February 4, the Federal Energy Regulatory Commission (FERC) released its Energy Infrastructure Update for December 2018, which gives the highlights of changes and expansions in the industry.

For natural gas pipelines, five were placed in service, two were certified, and six more were proposed; there were no updates in December for storage facilities or liquified natural gas (LNG) imports of exports. The total number of pipeline projects placed into service in 2018 was 26, which is lower than the 32 in 2017. There were 48 certified in both 2017 and 2018. No storage facilities were placed into service in 2018, and only one was in 2017. There were four storage facilities certified in 2018, compared to only two in 2017. One LNG export was placed into service, compared to three in 2017. There was one import/export facility certified in 2018, and there were none in 2017.

For hydropower, one capacity amendment was filed in December, and another hydropower facility was licensed. In 2018, two facilities files for 10-MW Exemption and three filed for capacity amendments. Only one license was issued last year, and one capacity amendment was issued. Two licenses were placed in service in 2018.

In December, no new coal facilities were put into service, and only four were put in service in 2018; three were put in service in 2017. Seven new natural gas facilities were put in service, and 103 were opened in 2018; this is compared to the 106 put in service in 2017. No nuclear facilities opened in December, but five opened last year; only one opened in 2017. No oil facilities opened in December either, but 14 opened in 2018, compared to the 37 opened in 2017. No hydropower facilities opened either, but 10 opened in 2018; 14 opened in 2017. Twelve wind power facilities opened in December, 55 opened in 2018; 83 opened in 2017. No biomass facilities opened in December, but 13 opened last year; 27 opened in 2017. Two geothermal steam facilities opened, half of the four that opened last year; only two opened in 2017. There were 15 solar facilities opened in December, and 429 total in 2018; in 2017 750 opened.

There were a number of suggestions for additions and retirements to take place by January 2022. One coal addition was suggested, and 57 retirements. For natural gas, 276 additions were suggested and only 94 retirements. There were 11 additions suggested for nuclear power, and nine retirements. Seventeen oil additions and 24 retirements were suggested. For hydropower, 237 additions and 20 retirements were suggested. There were 530 wind additions and no retirements suggested. There were 53 biomass additions and 29 retirements recommended. For geothermal steam, 19 additions and no retirements were suggested. Solar power saw the largest recommended additions with 2,278 and only five retirements.

In December, 20.2 miles of electric transmission projects of less than 230 volts were completed, compared to 54 miles of in December 2017. That same voltage has 327.3 miles in all of 2018, compared to 329.3 in 2017. For voltages of 345, there were 161.8 miles completed in December, compared to 32.5 miles in December 2017. In all of 2018, 714.5 miles were completed, compared to 363.1 miles in 2017. For 500 voltage, there was none in December, only 69.4 miles in 2018; there were no miles completed in 2018. In total, 182 miles were completed in December, compared to 86.5 miles in December 2017. In all of 2018, a total of 1,111.2 miles completed; 692.4 miles were completed in 2017.

FERC’s Final Statement for the Driftwood LNG Project

FERC’s Final Statement for the Driftwood LNG Project

On January 18, Federal Energy Regulatory Commission (FERC) issued their final Environmental Impact Statement for the Driftwood LNG Project. The Driftwood Project requested authorization “construct and operate liquefied natural gas (LNG) export facilities and certain interstate, natural gas transmission pipeline facilities in Evangeline, Acadia, Jefferson Davis, and Calcasieu Parishes, Louisiana.”

There are two main parts to the Driftwood Project:

  1. “The construction and operation of the LNG Facility, which includes five LNG plant facilities to liquefy natural gas, three tanks to store the LNG, LNG carrier loading/berthing facilities (Marine Facility), and other appurtenant facilities at a site near Carlyss, Calcasieu Parish, Louisiana”
  2. “The construction and operation of about 96 miles of pipeline, three new compressor stations, and 15 new meter stations.

They anticipate the Driftwood Project will produce approximately “27.6 million tonnes per annum of LNG for export.”

FERC determined the Driftwood Project will have significant adverse effects on the environment. “However, they would be reduced to less than significant levels with the implementation of Driftwood’s proposed impact avoidance, minimization, and mitigation measures and the additional measures recommended by staff.” FERC reached these conclusions through “information provided by Driftwood and through data requests; field investigations; literature research; geospatial analysis; alternatives analysis; public comments and scoping sessions; and coordination with federal, state, and local agencies and Indian Tribes.”

“The following factors were also considered in our conclusions:

  • The LNG Facility site would be in an area currently zoned for heavy industrial use, which is consistent with other industrial facilities along the Calcasieu Ship Channel.
  • The Pipeline would parallel or be collocated with other disturbed right-of-way corridors (with pipelines or utilities) for about 68 miles (about 71 percent of the route).
  • Driftwood would construct the Project using a number of Project-specific plans designed to minimize impacts. These include: Construction Environmental Control Plan; Driftwood Upland Erosion Control, Revegetation, and Maintenance Plan and Wetland and Waterbody Construction and Mitigation Procedures; construction Spill Prevention, Control, and Countermeasures (SPCC) Plan; Unanticipated Discoveries Plan; Horizontal Directional Drill Plans; Erosion and Sedimentation Control Plan; and Fugitive Dust Management Plan. Driftwood would also develop and implement an operations SPCC Plan.
  • The U.S. Coast Guard issued a Letter of Recommendation indicating the Calcasieu Ship Channel would be considered suitable for the LNG marine traffic associated with the Project.
  • The LNG Facility design would include acceptable layers of protection or safeguards that would reduce the risk of a potentially hazardous scenario from developing into an event that could impact the offsite public.
  • The Pipeline and associated aboveground facilities would be constructed, operated, and maintained in compliance with Department of Transportation standards published in 49 CFR 192.FERC staff would complete consultations with resource agencies to ensure compliance with Section 7 of the Endangered Species Act; and Section 106 of the National Historic Preservation Act.
  • Driftwood would follow an environmental inspection program, including Environmental Inspectors, to ensure compliance with the mitigation measures that become conditions of the FERC authorization. FERC staff would conduct inspections throughout construction, commissioning, and restoration of the Project.”

“FERC staff would complete consultations with resource agencies to ensure compliance with:

  • Section 7 of the Endangered Species Act; and
  • Section 106 of the National Historic Preservation Act.”

FERC also came up with some recommendations for Driftwood to implement in order for them to reduce the impact even further. These recommendations include “that Driftwood should implement specific to engineering, vulnerability, and detailed design of the LNG Facility, and ongoing recommendations relating to inspections, reporting, notification, and non-scheduled events that would apply throughout the life of the LNG Facility.”

Final Environmental Impact Statement for the Northeast Supply Enhancement Project

Final Environmental Impact Statement for the Northeast Supply Enhancement Project

The Federal Energy Regulatory Commission (FERC) issued a final Environmental Impact Statement for the Northeast Supply Enhancement Project that was purposed by Transcontinental Gas Pipe Line Company, LLC. This Project would provide an estimated “400,000 dekatherms per day of natural gas” to customers in the New York City area.

“The final EIS addresses the potential environmental effects of the construction and operation of the following Project facilities: 

  • 10.2 miles of 42-inch-diameter pipeline loop in Lancaster County, Pennsylvania (the Quarryville Loop);
  • 3.4 miles of 26-inch-diameter pipeline loop in Middlesex County, New Jersey (the Madison Loop);
  • 23.5 miles of 26-inch-diameter pipeline loop in Middlesex and Monmouth Counties, New Jersey, and Queens and Richmond Counties, New York (the Raritan Bay Loop, which consists of 0.2 mile of pipe in onshore Middlesex County, New Jersey; 6.0 miles of offshore pipe in New Jersey waters; and 17.3 miles of offshore pipe in New York waters);
  • modification of existing Compressor Station 200 in Chester County, Pennsylvania;
  • construction of new Compressor Station 206 in Somerset County, New Jersey; and
  • ancillary facilities (including cathodic protection systems, new and modified mainline valves with tie-in assemblies, new and modified launcher/receiver facilities, and facilities to connect the Raritan Bay Loop to the existing Rockaway Delivery Lateral at the Rockaway Transfer Point).”

FERC determined that the Project would have adverse impacts on the environment, though most of them would be temporary, only occurring during the construction of the Project. “Long-term impacts on air quality and noise would result from the operation of Compressor Station 206. We also conclude that, with implementation of Transco’s impact avoidance, minimization, and mitigation measures, as well as their adherence to our recommendations, all Project effects would be reduced to less-than-significant levels.

“Although many factors were considered during our environmental review, the principal reasons for these conclusions are as follows:

  • The Quarryville and Madison Loops would be collocated with existing Transco facilities for 97 percent and 100 percent of their lengths, respectively, with a typical offset of 25 feet from existing pipelines. Some workspace needed to construct the loops would overlap with Transco’s current right-of-way, reducing construction-related impacts.
  • A high level of public participation was achieved during the pre-filing and post-application review processes and helped inform our analysis.
  • Compressor Station 206 would comply with operating air permit conditions, and emissions would meet the National Ambient Air Quality Standards and other applicable standards that are protective of public health and welfare. Operating noise from the facility would meet our requirements at noise sensitive areas and the facility would be visually screened from surrounding viewpoints. All Project facilities, including Compressor Station 206, would be designed, constructed, operated, and maintained in accordance with U.S. Department of Transportation safety requirements that are protective of public safety.
  • Direct and indirect construction emissions of nitrogen oxides would be offset through direct mitigation or the purchase of Emission Reduction Credits and Creditable Emissions Reductions, thereby conforming with the New York and New Jersey State Implementation Plans with respect to the New Jersey-New York-Connecticut Interstate Air Quality Control Region.
  • The proposed route and construction methods for the Raritan Bay Loop were developed in consultation with the USACE and other agencies to minimize crossing designated anchorage areas, meet USACE marine traffic safety requirements, and reduce impacts on water quality and aquatic wildlife. Sixty-four percent of the offshore loop would be installed using a jet trencher, which would not require the removal and disposal of seafloor sediment. Thirty-one percent of the offshore loop would be installed using a clamshell excavator fitted with an environmental bucket, and an environmental clamshell would also be used to excavate horizontal directional drill (HDD) entry and exit pits. The remainder of the offshore loop would be installed via HDD, thereby avoiding direct seafloor impacts. Project-related turbidity would be temporary, and most sedimentation would occur near to the approximately 87.8-acre area of seafloor that would be directly affected by construction. In addition, Transco consulted with the National Marine Fisheries Service (NMFS), New Jersey Department of Environmental Protection, and New York State Department of Environmental Conservation to minimize construction conflicts with time of year restrictions for certain marine species to the extent practicable. As a result, impacts on aquatic resources would be temporary and minor to moderate.
  • We evaluated numerous alternatives to Transco’s proposal and determined that the alternatives would either not meet the stated purpose and need of the Project, would be infeasible, or would not provide a significant environmental advantage when compared to the proposed Project.
  • The Project area has been substantially impacted by human activity. The Project and other actions in the area would cumulatively impact some resources, but most cumulative impacts would be temporary or short-term and minor. Project impacts on forest resources would be permanent but minor when compared to the extent of forest in the region, and operating air emissions from Compressor Station 206 would permanently contribute to other emission sources in the region but would comply with applicable regulations.
  • An environmental inspection and monitoring programs would ensure compliance with all construction and mitigation measures that become conditions of the FERC We completed our consultation with the NMFS regarding the potential for the Project to impact Essential Fish Habitat species and National Oceanographic and Atmospheric Administration Trust Resources.authorizations and other approvals.
  • We would complete the process of complying with the Endangered Species Act prior to allowing any construction to begin.
  • We would complete the process of complying with section 106 of the National Historic Preservation Act and implementing the regulations at 36 CFR 800 prior to allowing any construction to begin.”

Part one of the statement can be read here, and part two can be read here.

FERC Proposes to Ease Regulatory Burden for Certain Market-Based Rate Sellers

FERC Proposes to Ease Regulatory Burden for Certain Market-Based Rate Sellers

On December 20, the Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) “to revise the horizontal market power analysis required for electric power sellers seeking to obtain or retain market-based rate authority in certain organized wholesale power markets.”

This NOPR helps to safeguard FERC’s “ability to prevent the potential exercise of market power by leaving in place other important protections to ensure just and reasonable rates” and it will “ease the regulatory burden for certain market-based rate sellers.” This NOPR will remove the requirement that sellers currently have to submit “indicative screens in any organized wholesale power market that administers energy, ancillary services and capacity markets subject to Commission-approved monitoring and mitigation.”

The NOPR is rooted in Order No. 697, because in that Order, FERC identified two screens to assess “horizontal market power for market-based rate sellers: the pivotal supplier screen and the wholesale market share screen. Each serves as a cross-check on the other to determine whether sellers may have market power and should be examined further when seeking market-based rates.”

In Order 697, two types of market-based rate sellers were created:

  • “Category 1 sellers are wholesale power marketers and wholesale power producers that own, control, or are affiliated with 500 MW or less of generation in aggregate per region; that do not own, operate, or control transmission facilities other than limited equipment necessary to connect individual generation facilities to the transmission grid – or have been granted waiver of the requirements of Order No. 888; that are not affiliated with anyone that owns, operates, or controls transmission facilities in the same region as the seller’s generation assets; that are not affiliated with a franchised public utility in the same region as the seller’s generation assets; and that do not raise other vertical market power issues. Category 1 sellers are not required to file regularly scheduled updated market power analyses
  • Market-based rate sellers that do not fall into Category 1 are designated as Category 2 sellers and are required to file updated market power analyses every three years”

The current market-based sellers that are “in organized wholesale power markets that do not administer these types of capacity markets… would be obliged to submit those indicative screens if they wish to sell capacity.” It also proposes that in the event of one of the screens failing, “market-based sellers in those markets may submit a delivered-price test or other evidence or propose other mitigation for capacity sales in these markets.”

All of the market-based sellers will “still be required to file a vertical market power analysis as well as an asset appendix, which provides comprehensive information relevant to determine a seller’s market power, including: generators owned or controlled by the seller and its affiliates; long-term firm power purchase agreements of the seller and its affiliates; and electric transmission assets, natural gas intrastate pipelines and intrastate natural gas storage facilities owned or controlled by the seller and its affiliates.”