FERC Testifies before the House Committee on Energy and Commerce, Subcommittee on Energy, on Oversight of FERC: Ensuring Its Actions Benefit Consumers and the Environment, Part I: Chairman Neil Chatterjee and Commissioner Cheryl A. LaFleur

FERC Testifies before the House Committee on Energy and Commerce, Subcommittee on Energy, on Oversight of FERC: Ensuring Its Actions Benefit Consumers and the Environment, Part I: Chairman Neil Chatterjee and Commissioner Cheryl A. LaFleur

On June 12, the Chairman and Commissioners of the Federal Energy Regulatory Commission (FERC) testified before the Subcommittee on Energy Committee on Energy and Commerce on the oversight of FERC. The full hearing can be watched here. This is the testimony of Chairman Neil Chatterjee and Commissioner Cheryl A. LaFleur.

Chairman Chatterjee’s Testimony

Chatterjee pointed out that there have been some major changes in the energy industry over the last decade, and that FERC has worked to “remain vigilant about these changes and respond to them in ways that enhance competition in electricity markets, support the resilience of the bulk-power system, and lower costs to consumers.” He said one of the more recent changes was “the improvement in electric storage technologies.” He highlighted some of FERC’s work “regarding the participation of electric storage resources in wholesale electricity markets as an example of how FERC is responding to our evolving energy landscape.”

“Traditionally, a variety of factors have created challenges to storage resources’ participation in the wholesale electric markets,” Chatterjee said. This led FERC to issue Order No. 841 in 2018, “to remove barriers to the participation of electric storage resources in the capacity, energy, and ancillary services markets operated by regional transmission organizations (RTOs) and independent system operators (ISOs).” He said that the result of this order should lead to “an increase in the deployment of storage resources, which should result in greater reliability and lower prices for customers by enhancing competition.”

He explained that FERC has also been “evaluating barriers to the participation of distributed energy resource aggregations in the markets operated by RTOs and ISOs.” In 2018 a technical conference held by FERC staff, they worked to “gather more information regarding the participation of distributed energy resource aggregations in wholesale electricity markets, as well as to discuss more broadly the potential effects of distributed energy resources on the bulk-power system.”

Chatterjee also discussed the cyber and physical security issues affecting the energy infrastructure. “America’s critical infrastructure is increasingly under attack by foreign adversaries. The Department of Homeland Security (DHS) and Federal Bureau of Investigation have issued multiple public reports describing cyber-intrusion campaigns by foreign government actors against our critical infrastructure, including the electric grid.”

“Physical and cyber-attacks on our critical infrastructure systems have the potential to create significant, widespread, and potentially devastating effects” an attack could have. He explained that FERC has been working “to address cyber and physical security risks as consistent with section 215 of the Federal Power Act, which grants us the authority to approve and enforce mandatory Reliability Standards developed by the North American Electric Reliability Corporation (NERC).”

Chatterjee said FERC issued two orders in 2018 to help improve security. “First, at our October 2018 Commission Meeting, we approved NERC’s proposed Reliability Standards to address supply chain threats… Second, at our July 2018 Commission Meeting, we approved a final rule directing NERC to expand reporting requirements for critical systems. That final rule 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 DHS.”

He said FERC’s Office of Energy Infrastructure Security has been working “with partners in industry, states, and other federal agencies to address both cyber and physical security issues for critical energy infrastructure. These initiatives include, among other things, voluntary architecture assessments of interested entities, classified briefings for state and industry officials, and joint security programs with other government agencies and industry.”

LaFleur’s Testimony

LaFleur said that since the wholesale electric power markets were created 20 years ago, they have grown to the point that they now serve over two-thirds of the country. “These markets save customers money by driving the efficient dispatch of resources over a large footprint, facilitate the introduction of innovative technologies and greater customer-side participation in the power supply, and, depending on the underlying state regulatory construct, shift investment risk from electricity customers to company shareholders.”

She said there are some challenges the markets face, but even with those concerns, “participation in organized markets continues to expand, with utilities and states in the West and Southeast exploring integration into existing organized markets or the creation of new regional markets.”

She explained that recently ” there has been significant debate over whether power markets are “real” markets. Frankly, this debate concerns me, as I have observed it often occurs in conjunction with arguments favoring intervention on behalf of particular types of resources, at the expense of economic efficiency and therefore customer benefits.” LaFleur said that there needs to be regulation in every market to make sure it stays both fair and effective, but “the real-time nature of electricity, which requires the balancing of load and supply second by second, leads to a more complex market than many others, and requires more comprehensive regulation to ensure its proper function.”

Resource selection, Lafleur says, is a big challenge for both FERC and the electric industry as a whole. She said this is a complex issue, ” particularly in states that restructured their retail electricity supply, given the divided regulatory responsibilities among the states, the organized markets, and the Commission.”

“In recent years … power markets generally have been roiled by low gas prices and by the build-out of renewables that have different cost, operating, and geographic characteristics than traditional fuel-based generation. These lower cost resources have significantly decreased wholesale power prices, to customers’ benefit, but have also threatened the financial viability of certain traditional resources, particularly coal and nuclear plants.” Several states responded to those changes by seeking “either to retain resources that are not thriving in the market, or to accelerate the resource change by supporting new resources that the market would not otherwise procure.”

Another major issue that FERC is facing, according to Lafleur is: “once we have selected the resources we need for the future – whether by market forces, integrated resource planning, or some combination – how do we price and dispatch them?” There is evidence from all over the country that, in both “organized markets and bilateral market regions, indicates that a fundamental shift in how we procure and pay for energy is underway.”

It was only recently that it stopped being “accepted without question that electric power was priced on volume, since a major component of cost was the commodity cost of the fuel burned to generate it. Baseload, intermediate, and peaking resources each played a well-understood role in helping to balance load.” She said that the data from more recent years shows that “cost curves, which traditionally have identified baseload resources as the cheapest and peaking resources as the most expensive, now look differently in many areas. With persistently low natural gas prices, zero marginal cost renewable resources, and distributed energy resources changing the shape of load curves, the traditional cost structures that supported resources may no longer provide appropriate compensation.”

“To help adapt to the new resource mix, regional market operators and others are considering new ways of paying for power, with a focus on services instead of volume. This change is visible in the energy and ancillary services markets, with services such as flexible ramping products, scarcity pricing, new forms of reserves, and a greater attention to essential reliability services. In addition, some regions have revised their capacity markets to better ensure resource performance.”

FERC has been taking “steps to ensure that new resources, including storage, variable resources, demand response, and distributed energy resources, can compete to provide services that customers need.”

Lafleur also addressed the use of gas energy: “The growth in domestic natural gas production and gas-fired electric generation has led to considerable buildout of the nation’s gas pipeline network. I have called for reconsideration of how the Commission determines the need for pipelines to reflect market conditions and assess on a regional basis whether more infrastructure can be supported for these long-lived assets.”

She says that she also thinks FERC “must do a better job of assessing and considering the climate impacts of gas pipelines and liquefied natural gas (LNG) projects. Before determining whether a proposed pipeline project is in the public interest under the Natural Gas Act (NGA), the Commission must disclose and consider the project’s environmental impacts under the National Environmental Policy Act (NEPA).” However, when it comes to LNG projects, FERC “must find that the proposed LNG export facility is not inconsistent with the public interest under the Natural Gas Act, while the Department of Energy (DOE), not FERC, considers the public interest regarding the export of the gas itself.”

“In May of 2018, the Commission elected to remove much of the greenhouse gas (GHG) quantification and consideration from orders going forward. I disagree with this decision and continue to advocate that the Commission undertake robust climate analysis; specifically, quantifying, considering and assessing the significance of the direct, indirect, and cumulative GHG emissions from proposed projects.” Lafleur explained that she will conduct her “own GHG calculation and analysis to weigh against the pipeline benefits and set out my thinking in separate concurring statements.”

Energy Infrastructure Update for April 2019 Issued by FERC

Energy Infrastructure Update for April 2019 Issued by FERC

On June 7, the Federal Energy Regulatory Commission (FERC) released their Energy Infrastructure Update for April, related to natural gas and hydropower, and covering the highlights for electric generation and transmissions.

In April, six new pipeline projects were certified and another one was proposed. Two Liquefied natural gas (LNG) import/export projects were certified.

In the year thus far, a total of four pipeline projects have been placed into service, compared to three in the same period in 2018; 13 more have been certified, compared to 19 at this time last year. One LNG storage facility has been certified, compared to three last year.

For LNG imports and exports, two exports have been placed in service this year, compared to one in 2018; four import/exports have been certified this year, compared to none at this point in 2018.

For hydropower, one license was filed in April, and that is the only activity in April. Another two facilities have filed capacity amendments in this year so far.

In April there were no new coal facilities, as there have been for all of 2019 to that point; there were four at this time in 2018.

There was one new natural gas unit, making 22 for the year to date; there were 26 at this time in 2018. There has been nothing new for nuclear power this year; there were three at this point last year. One new oil facility was added in April, making it a total of three for the year; compared to 10 from this time last year. There were no hydropower units added, but there have been four this year; compared to six last year. There was one wind power unit added, making it a total of 18 this year; compared to 17 last year. There have been no new biomass units added this year, compared to five last year. There have been no new geothermal steam units added this year either, and only two were added in this period last year. Four new solar powered units were added in April, making a total of 102 this year; compared to 213 at this time last year.

There were many proposed additions and retirements in April, to be done by May 2022. There were two proposed additions for coal, both are considered highly probable, and 50 proposed retirements. There were 226 proposed additions for natural gas, 110 are highly probable, and 109 units were proposed retired. Nuclear power had 11 additions proposed, three are highly probable, and eight proposed retirements. There were 11 additions for oil, 11 are highly probable, and there were 26 retirements. Hydropower had 224 additions, 82 highly probable, and 19 retirements. There were 543 additions for wind, 140 highly probable, and one retirement. There were 64 biomass additions, 29 highly probable, and 30 retirements. There were 18 geothermal steam additions, six highly probable, and no proposed retirements. Solar power had 2,510 additions proposed, 527 highly probable, and one retirement.

For electric transmissions, in the ≤230 range, 71 miles of line was laid in April, making a total of 91 this year; compared to April 2018 with 11 miles of line and a total of 392.3 in all of 2018. There were 1,748 miles of line proposed to be put in service by May 2021, and 532.1 were highly probable. In the 345 voltage, four miles of line were completed, making a total of 169 this year; there were 70 in April 2018, and 819.3 in all of 2018. There were 2,712 miles proposed, 1,067 considered highly probable. In the 500-voltage range, there were none laid in April, of this year or last, and only a total of 7.4 miles in 2019 this year total, and 69.4 in 2018; 1,662 miles were proposed additions, 738 of which are highly probable. A total of 75 miles were laid in April, close to the 81 in 2018; there have been 267.4 miles this year so far, compared to 1,281 in 2018. A total of 6,122 miles have been proposed, and 2,337.1 are considered highly probable.

FERC Has Approved Freeport LNG’s Request

FERC Has Approved Freeport LNG’s Request

The Federal Energy Regulatory Commission (FERC) on May 16, approved the Freeport LNG terminal in Texas’ request for construction of the Train 4 expansion. This is the fourth liquefied natural gas (LNG) export project that FERC has approved this year. Freeport LNG filed an application for the expansion in June 2017.

“I’m proud of the efforts by the Commission and its staff to process today’s and our previous LNG orders,” FERC Chairman Neil Chatterjee said. “Exporting LNG from the United States can help increase the availability of inexpensive, clean-burning fuel to our global allies who are looking for an efficient, affordable and environmentally friendly source of generation.”

This expansion “involves construction of a liquefaction unit similar to Freeport’s other three units at the site, as well as associated pipelines, storage vessels and related facilities.” It should allow 0.74 billion cubic feet of natural gas per day when it’s finished.

Two of FERC’s Commissioners released individual statements about this ruling, Cheryl A. LaFleur and Richard Glick. LaFleur wrote that she concurs with the approval, while Glick dissents. Glick wrote that he dissents for a few reasons, including that in his opinion, “it violates both the Natural Gas Act (NGA) and the National Environmental Policy Act (NEPA).”

To read the entire approval, click here.

Statement of Commissioner McNamee

Statement of Commissioner McNamee

On May 16, the Federal Energy Regulatory Commission (FERC) released an order for rehearing and clarification on Order No. 841, “amending its regulations under the Federal Power Act to remove barriers to the participation of electric storage resources in the capacity, energy, and ancillary service markets operated by Regional Transmission Organizations and Independent System Operators.” FERC Commissioner Bernard L. McNamee released a statement to argue his positions on some of the issues in the rehearing order. McNamee decided to issue a separate statement “because I am concerned that, like Order No. 841, today’s order on rehearing fails to recognize the states’ interests in ESRs located behind a retail meter (behind-the-meter) or connected to distribution facilities.”

In this statement, McNamee says that “I am troubled, however, that the Storage Orders do not fully respect or consider the impact they may have on local distribution systems, the states that regulate those local distributions systems, and local retail customers. To that end, I dissent from today’s order. I would have granted the rehearing requests asking the Commission to reconsider: (i) its finding that it has jurisdiction over whether ESRs located behind-the-meter or on the local distribution system are permitted to participate in the RTO/ISO markets through the ESR participation model and thereby asserting jurisdiction over distribution facilities; and (ii) its failure to provide states the opportunity to opt-out of the participation model created by the Storage Orders.”

“Electric energy storage resources (ESRs) have the potential to transform the electricity industry.” This is because they “will allow the electric transmission system to take full advantage of periods of high generation from intermittent resources, such as wind and solar, and use that energy in times when those resources are not available, but energy is needed.” He explained that there has been a growing amount of ESRs participating in the electricity market, which will allow a “greater shifting between generation and load — thereby enhancing reliability and market signals.” He says the ESRS can make a significant impact on the market and economic efficiency, which has to date been unattainable by the industry and its consumers.

“Order No. 841-A mandates that ESRs be permitted to use distribution facilities so that they may access the wholesale electric market,” McNamee writes. “There is no doubt that the participation of ESRs behind-the-meter or on the distribution lines can ‘affect wholesale rates,’ but in order to ‘affect’ wholesale rates such ESRs must first have access to the wholesale market, and they can only do so by using distribution facilities. In my view, the FPA does not provide the Commission with the authority to require that distribution facilities permit ESRs to use those facilities to access wholesale markets.”

For an ESR that’s “located either behind-the-meter or on the distribution system, the only way it can sell its energy at wholesale is by using distribution facilities to deliver energy to the wholesale market.” FERC concluded in Order 841 “that because ESRs’ sales and purchases can affect wholesale rates, the Commission therefore has the authority to dictate that ESRs have access to the wholesale market through distribution facilities… It is only when an ESR is provided access to the wholesale power markets through the distribution facilities that the Commission can exercise its authority; but the Commission cannot mandate that such access be provided on the local distribution facilities. That decision remains with the local distribution utilities and the states that regulate them.”

“In Order No. 841, the Commission asserted that because ESRs can [affect] wholesale rates, ESRs must be allowed to connect behind-the-meter and to the distribution facilities in order to participate in the wholesale markets… I believe that the requirement in the Storage Orders that states must permit distribution and behind-the-meter ESRs to use distribution facilities to access the wholesale markets creates a regulatory plan that fails to ‘happen exclusively’ on the wholesale market and fails to exclusively govern the wholesale market’s rules.”

At one point, FERC “considered a request for a declaratory ruling that, among other things, found the Commission had exclusive jurisdiction under the FPA to regulate the participation of certain EERs in wholesale electricity markets and that the states lacked the authority to bar or otherwise interfere with the participation of EERs in those markets.”

“The Storage Orders will likely result in day-to-day operational impacts on the distribution system greater than those presented by EERs or DR, but without providing states an opportunity to avoid these impacts by allowing them to opt out… An ESR’s activity quite literally pushes or pulls energy across the distribution facilities and thereby has a very real physical impact on the distribution system. The physical nature of an ESR’s activities may impact the operations of distribution-level facilities as well as their safety and reliability in a manner that DR’s and EERs’ voluntary decision not to consume electricity does not… The real physical and operational impacts ESRs have on the distribution system in my estimation weigh in favor of the Commission exercising its discretion to provide an opt-out to the states in this matter.”

“I am concerned that the Storage Orders potentially will create complications for, and impact the day-to-day operations and management of, the distribution system – as well as its safety and reliability – in a manner that is in fact greater than the impact of demand response resources because ESRs actually inject energy into the system.”

“Order No. 841 holds that ‘state responsibilities include, among other things, retail services and matters related to the distribution system, including design, operations, power quality, reliability, and system costs.’ However, the majority in Order No. 841-A dismisses the issue of increased cost on the distribution system as ‘outside the scope of this proceeding’ and argues that ‘we are not changing the responsibilities of the distribution utilities.’” McNamee says he disagrees with this, because “it is clear that many parties feel strongly that the Storage Orders do in fact increase their responsibilities, and if the majority does not want to address these issues in this proceeding, then they should at least provide an option for states to avoid these costs by opting out.”

“The majority also should not dismiss concerns over equity or cost allocation. When a distribution utility is concerned that it ‘will need to harden the underlying distribution system to support bidirectional power flows and pay for substantial metering upgrades’ to accommodate ESRs, and that the associated costs ‘could be trapped at the distribution level and allocated to end-users rather than wholesale market participants,’ in my view the Commission should not flatly disclaim involvement. The majority is willing to assert jurisdiction over the distribution system through the participation model, but they are unwilling to confront or take responsibility for the practical ramifications of their decisions.”

“In the complex and overlapping jurisdictions of electricity, a retail customer with a complaint or question about his or her bill or service may find it difficult to know whom to contact about that service. When service involves the distribution system, it is natural for a customer to call the local utility or the state public utility commission. The Commission should be cognizant that, by denying states an opt-out provision with respect to the Storage Orders, the majority is not only placing a burden on the distribution utility or the state to address any impacts of ESRs on the distribution system, they are in effect asking the distribution utility or state to take ownership of and accountability for that burden.”

McNamee concluded saying that if ESRs have the “correct regulatory and policy framework,” they could “transform the electricity industry by unlocking significant economic and market efficiency benefits.”

The order for rehearing will become effective 90 days after its publication in the Federal Register.

FERC Staff Issues the Final Environmental Impact Statement for the Rio Grande LNG Project and Rio Bravo Pipeline Project

FERC Staff Issues the Final Environmental Impact Statement for the Rio Grande LNG Project and Rio Bravo Pipeline Project

On April 26, the Federal Energy Regulatory Commission (FERC) released their final Environmental Impact Statement for the Rio Grande LNG Project, which was proposed by Rio Grande LNG, LLC and Rio Grande Pipeline Company, LLC. The developers requested authorization to “site, construct, and operate the following facilities in Jim Wells, Kleberg, Kenedy, Willacy, and Cameron Counties, Texas:

  • “six liquefaction trains would be constructed and operated at the Rio Grande liquefied natural gas (LNG) Terminal, each with a nominal capacity of 4.5 million tons per annum of LNG for export, resulting in the LNG Terminal’s nominal capacity of 27.0 million tons per annum;
  • “four LNG storage tanks, each with a net capacity of 180,000 cubic meters;
  • “LNG truck loading facilities with four loading bays, each with the capacity to load 12 to 15 trucks per day;
  • “a refrigerant storage area and truck unloading facilities;
  • “a condensate storage area and truck loading facilities;
  • “a new marine slip with two LNG vessel berths to accommodate simultaneous loading of two LNG vessels, an LNG vessel and support vessel maneuvering area, and an LNG transfer system;
  • “a materials off-loading facility in the Brownsville Ship Channel;
  • “2.4 miles of 42-inch-diameter pipeline, including 0.8 mile of dual pipeline, to gather gas from existing systems in Kleberg and Jim Wells Counties (referred to as the Header System);
  • “135.5 miles of parallel 42-inch-diameter pipelines originating in Kleberg County and terminating at the Rio Grande LNG Terminal in Cameron County (referred to as Pipelines 1 and 2);
  • “four stand-alone metering sites along the Header System;
  • “three new compressor stations (one at the LNG Terminal site);
  • “two new interconnect booster compressor stations, each with a metering site; and
  • “other associated utilities, systems, and facilities (yards, access roads, etc.).”

The Impact Statement was “prepared in compliance with the requirements of the National Environmental Policy Act (NEPA), the Council on Environmental Quality regulations for implementing NEPA in 40 Code of Federal Regulations, Parts 1500–1508 (40 CFR 1500-1508), and FERC regulations implementing NEPA (18 CFR 380).”

While FERC staff made the conclusions and recommendations in the Impact Statement, FERC did receive input from “the U.S. Army Corps of Engineers, U.S. Coast Guard, Department of Energy, U.S. Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration, the DOT’s Federal Aviation Administration, the U.S. Fish and Wildlife Service, the National Park Service, the U.S. Environmental Protection Agency, and the National Oceanic and Atmospheric Administration – National Marine Fisheries Service.” While FERC received their input while making their decisions, these agencies may still develop their own recommendations for the Project, “if, after an independent review of the document, they conclude that their permitting requirements have been satisfied.”

FERC concluded that the construction and operation of the Project would have some adverse impacts on the environment, but they could be significantly reduced. But, this Project, “combined with other projects within the geographic scope, would result in certain significant cumulative impacts.” This was determined through a review of information provided by the Rio Grande Developers, and was “further developed from data requests; field investigations; literature research; geospatial analysis; alternatives analysis; public comments and scoping sessions; and coordination with federal, state, and local agencies and Native American tribes.” There are multiple reasons the Project could reduce the impact of the to less significant levels, but the main reasons are:

  • “The LNG Facility site would be in an area currently zoned for commercial and industrial use, along an existing, man-made ship channel.
  • “The pipelines would be collocated with, or adjacent to, other disturbed right-of-way corridors for about 66.0 percent of the routes.
  • “The pipelines would be installed by trenchless methods (horizontal directional drill [HDD] or bore) where applicable to avoid impacts on all major perennial streams (i.e., streams over 100 feet wide), as well as many smaller waterbodies, wetlands, and road crossings.
  • “RG Developers would follow the Project-specific Spill Prevention, Control, and Countermeasures Plans; Stormwater Pollution Prevention Plans; Unanticipated Contaminated Sediment and Soils Discovery Plan; Unanticipated Discovery Plan (for cultural resources); HDD Contingency Plan; Fugitive Dust Control Plans; Noxious and Invasive Weed Plan; and Migratory Bird Conservation Plan.
  • “The U.S. Coast Guard issued a Letter of Recommendation indicating the Brownsville Ship Channel would be considered suitable for the LNG marine traffic associated with the Project.
  • “The LNG Terminal 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 pipelines and associated above ground facilities would be constructed, operated, and maintained in compliance with DOT standards published in 49 CFR 192.
  • “RG Developers would implement their Project-specific Upland Erosion Control, Revegetation, and Maintenance Plan (Plan) and Wetland and Waterbody Construction and Mitigation Procedures to minimize construction impacts on soils, wetlands, and waterbodies.
  • “All appropriate consultations with the U.S. Fish and Wildlife Service and National Marine Fisheries Service (NMFS) regarding federally listed threatened and endangered species would be completed before construction is allowed to start in any given area.
  • “Consultation under the Magnuson Stevens Fishery Conservation and Management Act is complete, and NMFS does not have essential fish habitat conservation recommendations for the Project.
  • “All appropriate National Historic Preservation Act consultations with the Texas State Historic Preservation Office and the Advisory Council on Historic Preservation would be completed before construction is allowed to start in any given area.
  • “RG Developers would follow an environmental inspection program, including Environmental Inspectors, to ensure compliance with the mitigation measures that become conditions of the FERC authorizations. FERC staff would conduct inspections throughout construction, commissioning, and restoration of the Project.”

FERC also gave the Developers some site-specific measures to help mitigate the impact of both the construction and operation of the Project.

FERC Staff Issues Final Environmental Impact Statement for Grant Lake Hydroelectric Project

FERC Staff Issues Final Environmental Impact Statement for Grant Lake Hydroelectric Project

On May 1, the Federal Energy Regulatory Commission (FERC) issued their final Environmental Impact Statement for Grant Lake Hydroelectric Project, a five-megawatt project, proposed by Kenai Hydro, LLC. Kenai Hydro first filed its application for the Grant Lake Project in April 2016, and after amending their application in January, May, and August, a draft Environmental Impact Statement was issued in October 2018.

The Grant Lake Project will be located in Kenai Peninsula Borough, Alaska, on Grant Lake and near Grant Creek. It will “occupy 1,688.7 acres of federal lands within the Chugach National Forest, administered by U.S. Department of Agriculture, Forest Service.”

FERC has identified “the primary issues associated with licensing the project are erosion and sedimentation control; protection of aquatic habitats including stream flows, water temperature and spawning gravel recruitment and movement; recreation use in the proposed project area and potential conflicts with the Iditarod National Historic Trail; and the protection of cultural resources.”

FERC “recommended the staff alternative, which consists of most measures included in Kenai Hydro’s proposal, as well as many of the mandatory conditions and recommendations made by state and federal agencies, and some additional measures developed by the staff.”

In the Statement, Kenai Hydro said they would take the following measures to protect the environment:

“Project Construction

• “Designate a third-party environmental compliance monitor (ECM) to oversee construction activities and ensure compliance with measures to protect natural resources.

• “Develop an erosion and sediment control plan (ESCP) that includes best management practices (BMPs) to prevent sediment mobilized during construction from entering Grant Creek or Grant Lake.

• “Restore areas disturbed by construction to pre-existing conditions.

• “Develop a hazardous materials containment/fuel storage plan that includes measures to contain all hazardous materials used during construction.

• “Consult with the Alaska Department of Fish and Game (Alaska DFG), U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National Marine Fisheries Service, and U.S. Department of the Interior, Fish and Wildlife Service (FWS) to finalize design details for fish exclusion measures in the tailrace.

• “Consult with Alaska DFG’s habitat biologist to establish timing windows for instream construction and stream-crossing activities.

• “Develop a bear safety plan that includes: (1) keeping construction sites and refuse areas clear of substances that attract bears, (2) installing bear-proof garbage receptacles and other measures during construction to prevent bears from obtaining food or garbage, (3) minimizing possible conflict with bears during construction and operation, (4) establishing protocols for dealing with problem bears, 10 and (5) notifying authorities of any bear-human conflict.

“Project Operation

• “Provide the following minimum flows in the bypassed reach: 5 cfs from January 1 through July 31, 10 cfs from August 1 through September 31, 7 cfs from October 1 through October 31, and 6 cfs from November 1 through December 31 to protect aquatic habitat and support benthic macroinvertebrates.

• “Provide the following instantaneous minimum flows downstream of the tailrace: 60 cfs from January 1 through May 15, 80 cfs from May 16 through May 31, 150 cfs from June 1 through June 30, 195 cfs from July 1 through September 1, 150 cfs from September 1 through September 30, 125 cfs from October 1 through October 15, 72 cfs from October 16 through November 15, and 60 cfs from November 16 through December 31 to protect habitat for salmonids and benthic macroinvertebrates.

• “Use variable depth withdrawals from the project intake to control water temperature in Grant Creek.

• “Use variable depth withdrawals from the project intake to control water temperature in Grant Creek.

• “Provide channel maintenance flows of 800 cfs to the Grant Creek bypassed reach for a continuous 8-hour duration, once per year, in a minimum of 2 years in each moving 10-year period to promote sediment recruitment and transport from the bypassed reach to Grant Creek.

• “Limit upramping rates to 1 inch per hour during the winter (November 16 through May 15) and 2 inches per hour during the summer (May 16 through November 15). Limit downramping rates to 1 inch per hour from November 16 through May 15 and 2.25 inches per hour from May 16 through November 15.

• “Limit upramping rates to 1 inch per hour during the winter (November 16 through May 15) and 2 inches per hour during the summer (May 16 through November 15). Limit downramping rates to 1 inch per hour from November 16 through May 15 and 2.25 inches per hour from May 16 through November 15.

• “Implement the Operation Compliance Monitoring Plan (filed on January 16, 2018) that includes: (1) lake level and temperature monitoring in Grant Lake; (2) flow and temperature monitoring in Grant Creek bypassed reach; (3) flow and temperature monitoring in Grant Creek tailrace; (4) failsafe provisions; (5) a schedule for installing, maintaining, and collecting flow and temperature instrumentation; and (6) reporting.

• “Develop a spill prevention, control, and containment plan and a hazardous materials containment/fuel storage plan to prevent hazardous materials from entering Grant Creek or Grant Lake during construction and operations.

• “Implement the Biotic Monitoring Plan (filed on January 16, 2018) that includes monitoring juvenile and adult salmonid abundance and habitat use, and monitoring gravel transport in Grant Creek to assess project effects on salmonid spawning habitat.

• “Conduct biological monitoring in Grant Creek to determine the need for gravel augmentation as well as the effectiveness of the proposed enhancement/mitigation measures, including minimum flows in the bypassed reach and minimum flows downstream of the tailrace, and to evaluate the need for removal of a log jam to increase flow in a Grant Creek side channel.

• “Implement the Vegetation Management Plan (filed on January 16, 2018) that includes: (1) invasive plant management and control, (2) revegetation, (3) vegetation maintenance, (4) sensitive plant species protection and monitoring, and (5) pale poppy population management.

• “Implement the Avian Protection Plan (filed on January 16, 2018) that addresses migratory species and bald eagles and minimizes potential for electrocutions or collisions with the project transmission line.

• “Develop an Iditarod National Historic Trail (INHT) re-route plan that includes constructing the southern half of the proposed INHT re-route from the existing route to Grant Creek.

• “Restrict public access to the project using signage and gating/fencing of the access road to address local residents’ concerns about encouraging motorized use near the project and reduce the potential for unauthorized motorized use and on adjacent National Forest System lands (NFS lands).

• “Develop a fire prevention plan.

• “Implement the Historic Properties Management Plan (HPMP) (filed on January 16, 2018) to protect historic properties in the project area.”

FERC issued Directions to NYISO and PJM to Implement Tariff Changes

FERC issued Directions to NYISO and PJM to Implement Tariff Changes

On April 18, the Federal Energy Regulatory Commission (FERC) directed the New York Independent System Operator (NYISO) and PJM Interconnection (PJM) to begin implementing tariff changes in order to ensure that their pricing for fast-start resources is both reasonable and just. This concludes FERC’s investigations into PJM and NYISO regarding section 206 of the Federal Power Act; these investigations began in December 2017.

In the preliminary findings, FERC found both NYISO and PJM’s current practices to be “unjust and unreasonable because those practices do not allow prices to accurately reflect the marginal cost of serving load when a fast-start resource is needed to quickly respond to unforeseen system needs.”

These reforms are part of FERC’s broader price formation initiative. “Fast-start resources are typically committed in real-time, very close to the interval when needed, and can respond quickly to unforeseen system needs.” However, when there is no fast-start pricing, “some fast-start resources are ineligible to set prices, often due to inflexible operating limits.”

They also found that “even when fast-start resources can set prices, they may not be able to recover their commitment costs, such as start-up and no-load costs, through prices.” Because of this, “prices may not reflect the marginal cost of serving load, muting price signals for efficient investments. Several RTOs and ISOs have already implemented fast-start pricing practices to address these issues.”

In the April 18 order, FERC found that PJM and NYISO’s “fast-start pricing practices are unjust and unreasonable because they do not allow prices to reflect the marginal cost of serving load.” FERC addressed these findings by directing the “grid operators to change their fast-start pricing practices.”

“Specifically, the Commission is directing NYISO to make the following tariff revisions to its fast-start pricing practices: 

  • Modify its pricing logic to allow the start-up costs of fast-start resources to be reflected in prices;
  • Relax the economic minimum operating limits of all fast-start resources, including dispatchable fast-start resources, by up to 100 percent for the purpose of setting price.”

NYISO is required to make a compliance filing by the end of 2019, and it has to implement the tariff changes by the end of 2020.

“The Commission is requiring PJM to make the following tariff revisions: 

  • Implement software changes so that fast-start resources are considered dispatchable from zero to their economic maximum operating limits for the purpose of setting prices;
  • Apply fast-start pricing to all fast-start resources;
  • Alter its real-time energy market clearing process to consider fast-start resources in a way that is consistent with minimizing production costs;
  • Restrict eligibility for fast-start pricing to fast-start resources that have a start-up time (including notification time) of one hour or less and a minimum run time of one hour or less;
  • Include commitment costs in energy prices for fast-start resources in both the day-ahead and real-time markets;
  • Implement its proposal to use lost opportunity cost payments to offset the incentive for over-generation or price chasing.”

PJM has to make their compliance filing by the end of July 2019. PJM also has to “file a one-time informational report by August 30, 2019, explaining how the proposed tariff provisions do not raise new market power concerns.”