California Governor Asks FERC to Investigate Increase in Prices in Western Gas Markets
February 7, 2023
by Paul Ciampoli
APPA News Director
February 7, 2023
In a Feb. 6 letter to the Federal Energy Regulatory Commission, California Gov. Gavin Newsom asks FERC to “immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior, or other anomalous activities are driving these ongoing elevated prices in the western gas markets.”
In his letter to Acting FERC Chairman Willie Phillips, Newsom said that since late November 2022, wholesale natural gas prices throughout the West “have risen to alarming levels that greatly exceed prices in the rest of the country.”
Newsom said that electricity prices in the FERC-regulated California Independent System Operator Market and Western Energy Imbalance Market “have similarly escalated because electricity prices are directly affected by wholesale natural gas costs.”
He said that while wholesale natural gas price increases were exacerbated by early cold weather
in the western states, “those known factors cannot explain the extent and longevity
of the price spike.”
The extended high prices have prompted the California Public Utilities Commission and the California Energy Commission to convene an en banc meeting with market experts from across the country to explore all the possible drivers behind the wholesale natural gas price spikes, as well as any measures that could protect electric and gas utility customers, Newsom noted.
“However, it is clear that the root causes of these extraordinary prices warrant further examination,” he said.
“I therefore ask that FERC immediately focus its investigatory resources on assessing whether market manipulation, anticompetitive behavior, or other anomalous activities are driving these ongoing elevated prices in the western gas markets,” he said.
“And, if warranted, I ask that FERC bring its full enforcement powers and resources to bear to
protect customers. I also offer California’s resources to assist in any data collection that FERC may require.”
Study Finds Steeply Rising Interconnection Costs In PJM
February 6, 2023
by Peter Maloney
APPA News
February 6, 2023
The costs to connect a power project to the grid in the PJM Interconnection region have risen steeply, according to a new report by Lawrence Berkeley National Laboratory.
Interconnection costs have risen across the board, according to the report, Interconnection Cost Analysis in the PJM Territory.
For projects with completed studies and plants in service, costs have doubled. For active projects still in the interconnection queue, estimated costs have grown eightfold since 2019.
More specifically, average costs for completed projects have doubled, rising from a mean cost of $42 per kilowatt in 2000-2019 to $84/kW in 2020-2022 and a median cost of $18/kW in 2000-2019 to $30kW in 2020-2022.
Costs of active projects in the queue have risen even more steeply, with mean costs growing from $29/kW in 2017-2019 to $240/kW in 2020-2022 and median costs rising from $8 in 2017-2019 to $85/kW in 2020-2022.
Withdrawn projects had the highest costs of all, with a mean cost of $599/kW in 2020-2022 and a median cost of $156.kW, which was likely a “key factor in those withdrawals,” the authors of the report said. “Project costs vary widely and a small number of high cost projects caused average costs to rise above median costs,” the authors noted.
The main driver behind the cost increases has been broader network upgrade costs, the Berkeley report found. Average costs for upgrades beyond the interconnecting substation have risen sharply since 2019, to $71/kW for complete projects, $227/kW for active projects, and $563/kW for withdrawn projects, the authors said.
A small subset of generators faces lower network upgrade costs by choosing interconnection services as an energy instead of a capacity resource, but those owners forfeit preferential treatment during high load hours, cannot participate in PJM’s capacity market, and may face increased curtailment, the report said.
PJM’s interconnection queue has ballooned in recent years, with 2021’s active queue increasing by 240 percent compared with year-end 2019, reaching a level nearly twice as large as PJM’s peak load in recent years of about 155 gigawatts.
At year-end 2021, PJM had 259 GW of generation and storage capacity actively seeking grid interconnection. Most of that capacity is represented by solar interconnection requests, 116 GW, followed by standalone battery storage, 42 GW, wind projects at 39 GW, and solar-battery hybrid projects at 32 GW.
PJM’s data also shows that 79 GW of projects have dropped out of the queue because they entered service while 432 GW of projects dropped out of the queue because they withdrew.
The rapid growth of interconnection requests, along with lengthy study timelines and high project withdrawal rates, motivated PJM to reform its interconnection process in 2022, adopting a “first-ready, first-served” cluster study approach and increasing study deposits that are at risk if a project is withdrawn.
CAISO-WEIM Agreement Forges Path For Extended Day-Ahead Market
February 5, 2023
by Peter Maloney
APPA News
February 5, 2023
The governing bodies of the California Independent System Operator’s and the Western Energy Imbalance Market on Thursday approved initiatives establishing an extended day-ahead market.
The EDAM final proposal will allow WEIM entities that currently buy and sell energy in the real-time market to participate in an extended day-ahead market, giving them access to additional economic, environmental and reliability benefits and better position them to respond to operational challenges stemming from a changing resource mix and extreme weather events, CAISO said.
Along with the EDAM initiative, the governing bodies also approved a proposal that, among other things, would apply the existing joint approval authority of the WEIM’s board and governing body to the EDAM market rules.
The proposal would also encourage the WEIM Regional Issues Forum to engage more directly in the stakeholder process for establishing priorities on policy initiatives,
CAISO said its next step in the EDAM process is the development of tariff language through additional stakeholder engagement over the coming months, and then spend the rest of the year and part of 2024 focusing on implementation activities.
CAISO’s board of governors also adopted the Transmission Services and Market Scheduling Priorities Phase 2 initiative that supports grid reliability by providing a long-term approach to allocating transmission capacity to California load-serving entities while enabling external entities to obtain priority scheduling, or wheel-through rights, to transfer energy across the ISO’s system.
PacifiCorp in December announced its intention to join EDAM when it launches. In May, the Bonneville Power Administration became one of the newest members of the Western Energy Imbalance Market.
AMP Executives Elected to Serve in Industry Leadership Positions
January 23, 2023
by Paul Ciampoli
APPA News Director
January 23, 2023
American Municipal Power, Inc. recently announced that five AMP executives have been elected to serve in leadership positions among various industry organizations in 2023.
Specifically, Lynn Horning, director of PJM regulatory affairs at AMP, has been elected PJM Electric Distributor sector whip, while Steve Lieberman, vice president of transmission and regulatory affairs, will serve as North American Energy Services Board (NAESB) Wholesale Electric Quadrant, Markets/Brokers segment board of directors’ representative.
Also, Chris Norton, assistant vice president of RTO and regulatory affairs, has been elected NAESB Wholesale Electric Quadrant, Markets/Brokers segment and will serve as the Executive Committee representative.
Jeff Riley, rates and regulatory analyst, has been elected PJM Electric Distributor sector representative to the Finance Committee, while Shirley Schultz, manager of MISO regulatory affairs, has been elected MISO Transmission Dependent Utility sector alternate representative to the Advisory Committee.
AMP is the nonprofit wholesale power supplier and services provider for 133 members in Ohio, Pennsylvania, Michigan, Kentucky, Virginia, West Virginia, Indiana, Maryland and Delaware.
Texas Utility Regulators Adopt Performance Credit Mechanism Electric Market Design
January 20, 2023
by Paul Ciampoli
APPA News Director
January 20, 2023
The Public Utility Commission of Texas on Jan. 19 voted to adopt a performance credit mechanism electric market design option and a set of guiding principles for implementation to “strengthen reliability, accountability, and affordability of the Electric Reliability Council of Texas electric grid.”
The Commission said it will defer implementation of all elements of the PCM until Texas lawmakers
have an opportunity to review the PCM and its guiding principles and provide guidance or direction based upon the market design option’s merits.
A Jan. 19 memo from PUCT Chairman Peter Lake to his fellow commissioners said that the Commission would recommend the creation of a new reliability service to ensure enough dispatchable generation is available during periods of low renewable energy output. This new service would be based on the PCM concept detailed in a report from Energy and Environmental Economics, a consulting firm, which includes principles detailed in the memo.
The Commission said that adoption of the PCM market design meets the requirements of Senate Bill 3, as passed by the 87th Texas Legislature and signed into law by Governor Greg Abbott, which directed the PUCT to create grid reliability standards that ensure on-demand generation is available “during times of low non-dispatchable power production.”
In addition to adoption of the PCM, the Commission directed ERCOT to develop bridging options
to retain existing power plants and build new generation resources until the PCM can be fully
implemented and opened a project to evaluate and establish an appropriate reliability standard
for ERCOT.
The action is the culmination of 18 months of public and stakeholder engagement, analysis, and deliberation, the Commission noted.
Extreme Weather, Fuel Constraints Drove High, Volatile 2022 Electric Prices
January 12, 2023
by Peter Maloney
APPA News
January 12, 2023
Extreme weather, compounded by natural gas and coal constraints, resulted in higher and volatile wholesale electric prices in 2022, according to the Energy Information Administration.
Prices at all electricity trading hubs were higher in 2022 compared with 2021, except in the Electric Reliability Council of Texas region where Winter Storm Uri pushed prices to $1.800 per megawatt hour in February 2021 and making ERCOT’s 2021 annual average electricity price higher than in 2022, the EIA said.
The EIA, a part of the Department of Energy, cited four severe weather-related events in 2022 that contributed to volatility and pushed wholesale prices higher last year.
Last January, cold temperatures and a winter storm, combined with natural gas pipeline constraints in New England, caused New England wholesale electricity prices to rise, averaging $160/MWh in ISO New England that month.
In July, a heatwave in Texas created record-breaking electricity demand in ERCOT while wind generation provided less electricity than usual for several days during the heatwave as wind speeds dropped precipitously. Natural gas-fired generation increased to make up for the drop in wind generation, pushing up prices at the ERCOT North trading hub, which averaged $182/MWh that month.
An early September heatwave in the western United States resulted in record-breaking electricity demand and rising prices. The price increases started in the Northwest, where the Northwest Mid-Columbia market hub’s wholesale electricity price averaged $224/MWh that month. In California, natural gas-fired generation increased in the generation mix, resulting in higher electricity prices. In the California ISO (CAISO) region, the wholesale electricity price averaged $134/MWh that month.
In December, cold weather and winter storms in the Western Pacific regions led to record-high electricity prices of $283/MWh at the Northwest Mid-Columbia market hub while CAISO’s N-15 hub hit $257/MWh.
Once again, cold weather increased demand, which increased natural gas-fired generation. And the cold weather, along with supply constraints, caused natural gas spot prices in the western hubs to rise to about 10 times those at Henry Hub, the national benchmark price.
Early last year, natural gas prices were pushed higher by economic growth in Asia and constraints on pipeline and liquefied natural gas (LNG) exports to Europe from Russia. Meanwhile high international demand for natural gas increased U.S. LNG exports, causing natural gas prices to rise for domestic customers. Natural gas prices rose from $3.70 per million British thermal units (MMBtu) in early January 2022 to almost $10/MMBtu in late August 2022.
Milder temperatures and increased natural gas production lowered natural gas and electricity prices after the September heatwave and through early November. Natural gas prices then started to rise again as colder weather set in.
The limited availability of coal to substitute for higher-priced natural gas also contributed to higher electricity prices.
In 2022, railroad and coal mine labor shortages constrained coal supply and delivery to power plants throughout the summer, limiting utility operators’ ability to switch from relatively expensive natural gas to cheaper coal-fired generation.
President Biden Names Willie Phillips Acting Chairman of FERC
January 4, 2023
by Paul Ciampoli
APPA News Director
January 4, 2023
President Biden on Jan. 3 named Willie Phillips as acting chairman of the Federal Energy Regulatory Commission.
Richard Glick departed from FERC in early January after serving as chairman of FERC for the past two years.
Phillips joined FERC as a Commissioner in December 2021. Prior to that he served as the Chairman of the Public Service Commission of the District of Columbia, named to that role in 2018 and serving on the DCPSC since 2014.
Prior to the DCPSC, Acting Chairman Phillips served as Assistant General Counsel for the North American Electric Reliability Corporation, in Washington, D.C. Before joining NERC, he worked for two law firms where he advised clients on energy regulatory compliance and policy matters.
PacifiCorp Agrees to Join California ISO’s Extended Day-Ahead Market
December 13, 2022
by Paul Ciampoli
APPA News Director
December 13, 2022
PacifiCorp, a utility which operates in six states, recently announced its plan to join the Extended Day-Ahead Market (EDAM) being developed by the California Independent System Operator (CAISO), as well as the Western Power Pool’s Western Resource Adequacy Program (WRAP).
PacifiCorp is the first utility to sign on to the new Western day-ahead market.
PacifiCorp noted that it has been working with the CAISO and a wide range of stakeholders to develop the new day-ahead market. The EDAM builds upon CAISO’s existing Western Energy Imbalance Market.
Plans call for the EDAM to begin operation in 2024, subject to federal regulatory approval.
The current real-time WEIM optimizes the energy imbalances throughout the West by transferring energy between participants in 15-minute and 5-minute intervals throughout the day. The proposed EDAM builds on this real-time market by extending optimization to a high volume of resource commitments that must be made a day in advance, which are then re-optimized in the real-time WEIM as conditions change.
CAISO on Dec. 8 noted that the final EDAM proposal was released on December 7 and the CAISO Board of Governors and Western EIM Governing Body will be briefed on the proposal on December 14.
The final proposal will be brought forward to the CAISO Board of Governors and WEIM Governing Body for a decision under the joint authority decision framework on February 1 and filed with the Federal Energy Regulatory Commission later in 2023.
Pacific Power, a PacifiCorp division, serves customers in Oregon, Washington and California.
PacifiCorp is also joining the Western Resource Adequacy Program, which is managed by the Western Power Pool. PacifiCorp said it has worked extensively with the Western Power Pool and other potential participants in the development of the WRAP, which is expected to provide regionwide reliability benefits to it participants by pairing regional diversity with common resource adequacy standards.
This means WRAP participants will be held to common planning standards to serve winter and summer peak loads. The common planning standards and increased regional collaboration will create a pool of resources that can be used to serve load, if needed, thus increasing reliability for the entire region.
Maine’s Secretary of State Clears Path for Voters to Consider Public Power Utility in 2023
December 12, 2022
by Paul Ciampoli
APPA News Director
December 12, 2022
Maine’s Secretary of State Shenna Bellows in late November announced the completion of the certification of petitions that will allow voters in the state next year to consider replacing investor-owned utilities in Maine with a statewide, consumer-owned utility.
Bellows confirmed that 69,735 valid signatures were submitted for the initiative, enough to move forward to the November 2023 ballot.
The Maine Legislature will now consider this initiative, which would replace Central Maine
Power and Versant Power with a nonprofit, Maine-owned utility.
Legislators will have the opportunity to enact the bill as written or to send it forward to a statewide vote on the November 2023 ballot.
In October, a group in Maine called Our Power submitted more than 80,000 signatures from voters in 422 Maine towns.
Chelan PUD Commissioners Approve PUD Joining Resource Adequacy Program
December 12, 2022
by Paul Ciampoli
APPA News Director
December 12, 2022
Chelan PUD commissioners recently voted for the Washington State PUD to join the Western Resource Adequacy Program (WRAP), the first reliability planning and compliance program in the Northwest, which has been in the works since 2019.
About 26 utilities from Canada to northern California are participating in the voluntary, non-binding phase of WRAP.
Chelan said that while the Pacific Northwest typically produces abundant energy supply, “there are warning signs of a less certain future ahead: Increased demand for electricity, the rise of intermittent renewables like wind and solar, increased regulatory requirements, and more large-load industries moving to the West.”
WRAP has asked utilities to join the binding phase over the next several years, which means that utilities have guaranteed first priority to purchase energy from other member utilities in the event of a critical shortage. It also means that utilities may be subject to penalties if they don’t meet capacity requirements. The cost of joining is about $185,000 the first year, and $150,000 annually.
Chelan listed the benefits of WRAP as:
- Increased reliability as dozens of utilities coordinate a diverse portfolio of energy resources across a large geographical footprint. If one area is hard hit by a heat wave or cold snap, utilities can tap into an emergency supply of energy from WRAP instead of relying on the increasingly volatile energy market.
- Increased value of capacity, which means hydropower is well-positioned to become more valuable because of its flexible, 24/7 availability.
- Joining WRAP voluntarily makes legislative mandates less likely.
- Supporting the WRAP may increase the chance of success of future organized markets, which has had over 20 participants from the Pacific Northwest to the Desert Southwest. A resource adequacy program is a standard feature of an organized market. If Chelan PUD joins a future organized market, the organized market will most likely have similar rules to WRAP.
- Joining WRAP would allow Chelan PUD to have a lower planning reserve margin. That means Chelan PUD may have more energy available to sell and maintain low customer rates.
“If it doesn’t work out the way we anticipate, we can exit the program with a two-year notice at any time,” said Shawn Smith, Managing Director of Energy Resources.