NRG Energy on Thursday reported 2019 income from continuing operations of $4.1 billion, compared to $460 million for the previous year, the large difference driven by the release of a $3.5 billion tax valuation allowance. Adjusted EBITDA was almost $2 billion, up from almost $1.8 billion in 2018.
In a call with analysts, NRG CEO Mauricio Gutierrez highlighted the company’s signing of 1.6 GW of medium-term solar power purchase agreements in ERCOT, its $300 million acquisition of Stream Energy and the return of its 385-MW natural gas-fired Gregory plant in Corpus Christi, Texas, to service before the summer.
Gutierrez said the purchase of Stream, with 600,000 electricity and gas customers in Pennsylvania and Texas, adds “important capabilities to our retail portfolio,” aiding its move to balance generation and retail.
Adjusted EBITDA for generation rose 24% year-over-year to $1.1 billion on higher realized power prices. Retail EBITDA dropped 3% to $920 million primarily because of higher supply costs.
NRG generates electricity and provides electric power and natural gas to more than 3.7 million residential, small business, and commercial and industrial customers in the U.S. and Canada.
Texas Hold ’em
(1) ERCOT long-term load forecast; (2) Source: ERCOT Dec 2019 CDR; excludes Oklaunion starting fall 2020, Decker Creek STG 1 fall 2020 and Decker Creek STG 2 fall 2021; (3) Prior target reserve margin | NRG Energy
Electric demand in ERCOT continues to grow at the fastest pace in the nation, between 2 and 3% per year for the foreseeable future, the company reported. “This requires a tremendous amount of generation investments simply to maintain the current low reserve margin,” Gutierrez said.
The company expects ERCOT to remain tight and volatile for the foreseeable future. “Regulators in ERCOT continue to refine our scarcity pricing mechanism to incentivize new generation, which is predominantly renewable and intermittent, while adequately compensating existing resources that provide firm generation,” Gutierrez said.
“This ruling is just the most recent in a series of market reforms that PJM and FERC have undertaken since 2004 to protect the integrity of competitive markets,” he said.
Low Carb Diet
The company aims to reduce its carbon emissions by 50% by 2025 and to net zero by 2050.
“We are already 83% of the way to our 2025 goal, with clear line of sight to achieve it with our current portfolio,” Gutierrez said. “We have reduced our carbon emissions by 40 million metric tons in just the last 10 years. That is the equivalent of taking 9 million cars off the road every year.
| NRG Energy
“In just the last six years, coal as a percentage of our total revenues has decreased 55%, and that is inclusive of capacity revenues,” Gutierrez said. “This is an important distinction, as energy revenues have been the bulk of the decline, and our coal assets in the East now act primarily as insurance for grid reliability and not for electric generation.”
Public Service Enterprise Group CEO Ralph Izzo expressed skepticism Wednesday that New Jersey utilities will abandon the PJM capacity market over the expanded minimum offer price rule (MOPR).
“We will work cooperatively with the Board of Public Utilities in New Jersey and PJM to find the best path forward, whether that is to bid and clear the capacity auction under a business-as-usual scenario, or seek the FRR [fixed resource requirement] alternative in partnership with New Jersey to preserve its preferred zero-carbon resources,” Izzo said during PSEG’s fourth-quarter earnings call.
“New Jersey would have to have either a zonal or statewide FRR, which to me is suboptimal … because now you’re going to be solving a small problem with a rather large tool,” Izzo said. “If your aspirations are for 7,000 MW of offshore wind, you need to pull out 15,000 MW from the capacity market. Seems to be a bit of overkill.”
Taking the FRR option could leave behind a residual capacity market that is “grotesquely oversupplied … crushing capacity prices,” he added. “I mean, there’s just a ton of questions.”
Izzo noted that New Jersey will not have offshore wind collecting subsidies until 2024. “So, it doesn’t start paying double [for capacity] until the second auction from now. … I do think that there will be adequate time for New Jersey to avoid double paying for capacity 2024. It won’t be a walk in the park.”
FERC ordered PJM in December to expand its MOPR to include new state-subsidized resources, as well as existing nuclear units receiving zero-emission credits (ZECs) such as PSEG’s Hope Creek and Salem 1 and Salem 2 plants.
“The ability of the nuclear plants to clear in [PJM’s capacity market] will depend on the level of the applicable generic offer floors, as well as the offer floor levels that would be derived via the unit-specific exception, should one or more of the units elect that option,” the company said in its 10-K filing.
Bridgeport Harbor 5, a 485-MW combined cycle plant in Connecticut that began operating last year, is PSEG’s largest generating unit in New England. | PSEG
Izzo said he is optimistic because New Jersey’s Energy Master Plan expects nuclear power to be an important generation source through 2050, when the state hopes to reach its goal of 100% “carbon neutral” electric generation. “So that has to be economically supported,” he said. “No. 2, we have fossil assets that are located close to the load centers and have deliverability advantages that will [be] important factors in any capacity reliability construct that is created.
“And let’s remember that the underlying rationale for FERC’s action was to eliminate price suppression caused by units that were receiving out-of-market payments,” he added.
While Izzo said the company is “strongly supportive” of New Jersey Gov. Phil Murphy’s goals of reducing electric usage by 2% and gas usage by 0.75% in five years, he seemed to question the master plan’s long-term goal of cutting gas use to one-fifth of current consumption by 2050.
“From a practical standpoint, 80% of New Jersey households already use natural gas to heat their homes or to cook, and in fact, many of our customers converted to natural gas from using oil or electricity for these purposes,” he said. With a conversion cost of at least $10,000 per customer, the transition “would be a significant economic burden on every household and contrary to most customers’ personal preferences,” he said.
Earnings
PSEG reported operating earnings of $330 million ($0.64/share) in the fourth quarter, up from $284 million ($0.56/share) in 2018. For 2019, the company reported operating earnings of $1.67 billion ($3.28/share) versus $1.58 billion ($3.12/share) the year before.
The company said its ZEC revenues added 6 cents/share for the quarter and 18 cents/share for the year. The payments, equivalent to about $10/MWh, are recovered through a non-bypassable distribution charge of 0.4 cents/kWh.
The BPU has authorized ZEC payments through May 2022, a decision that has been appealed by the Division of Rate Counsel. State law requires PSEG to reapply for any subsequent three-year periods.
Net income for 2019 included a loss recorded on the third-quarter sale of PSEG Power’s 800-MW interest in the coal-fired Keystone and Conemaugh coal-fired units in Pennsylvania. The company said it expects to eliminate all coal-fired generation from its fuel mix by mid-2021 with the early retirement of Bridgeport Harbor 3, Connecticut’s last coal-fired generator.
The company said it has reached an agreement to sell its 200-MW interest in the Yards Creek pumped-storage generating station in New Jersey, which it owns jointly with FirstEnergy. “The sale reflects our ongoing commitment to optimize the value of the generating fleets,” the company said. “These proceeds will add to the improved cash flow at Power, given the completion of the combined cycle construction program and Power’s declining capital needs.”
PSEG Power completed its 1,800-MW combined cycle gas turbine construction program with the addition of the Keys Energy Center in Maryland and Sewaren 7 in New Jersey in 2018, as well as Bridgeport Harbor Station Unit 5 in Connecticut last year.
But he said the 485-MW Bridgeport Harbor 5, the company’s largest unit in New England, “cleared the 2019/20 auctions and locked in $231/MW-day capacity payments for seven years, thereby limiting our exposure to this latest auction result.”
Earnings call transcript courtesy of Seeking Alpha.
Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee, and ranking member Joe Manchin (D-W.Va.) unveiled their long-awaited energy legislation Thursday, incorporating some 50 bills previously approved by the panel.
The bill “will modernize domestic energy laws to ensure the United States remains a global energy leader while also strengthening national security, increasing our international competitiveness and investing in clean energy technologies,” she said in a statement. “By working together to pass it into law, we can promote a range of emerging technologies that will help keep energy affordable even as it becomes cleaner and cleaner. Our bill also addresses national needs by taking overdue steps to enhance our cybersecurity, grid security and mineral security. I’m proud of the bipartisan work we have done and encourage all members of the Senate to work with us to advance it through the legislative process.”
Murkowski’s previous efforts to update energy efficiency laws with former ranking member Maria Cantwell repeatedly fell short. But Murkowski indicated she had support from Senate Majority Leader Mitch McConnell (R-Ky.), who filed cloture on the motion to proceed to S.2657, a geothermal research and development bill by Murkowski and Manchin that she said will serve as the legislative vehicle for the bill. The Hill reported that the bill could reach the floor as soon as next week.
In addition to reauthorizing the Advanced Research Projects Agency – Energy (ARPA-E) through fiscal year 2025, the bill could mean higher salaries for some FERC employees and provide new markets for coal and natural gas. It includes initiatives for carbon capture, ocean energy, next generation nuclear power and advanced vehicles and would create incentives for utility investments in cybersecurity.
The bill won immediate support from the National Mining Association; ClearPath Action, a conservative clean energy group; the Nature Conservancy; and the Business Council for Sustainable Energy.
The American Council on Renewable Energy (ACORE) said it backed the bill’s support for energy storage. “However, all should understand that federal investment in future innovation, while constructive, is not nearly a sufficient response to the climate crisis. In 2020, any energy bill should include provisions to accelerate near-term renewable energy deployment. More specifically, ACORE calls on Congress to include critical clean energy tax incentives in this package.”
Below is a summary of some of the most significant provisions of the bill:
Energy Efficiency
Creates a pilot program to award grants to provide nonprofit buildings with energy efficiency materials;
Competitive grants for schools to make energy improvements;
Establishes a program to implement smart building technology and demonstrate the costs and benefits of smart buildings;
Extends existing federal building energy efficiency improvement targets through 2028, and adds water use reduction targets through 2030;
Requires development of a metric for data center energy efficiency;
Reauthorizes the Weatherization Assistance Program through FY 2025; and
Establishes rebate programs for the replacement of energy-inefficient electric motors and transformers.
Capacity Building and Workforce Development
Provides grants to colleges for building training and assessment centers and grants to partially cover the cost of training programs in energy-efficient building technologies;
Establishes a pilot program to provide competitively awarded cost-shared grants to support training and apprenticeship programs in renewable energy, energy efficiency, grid modernization or the reduction of greenhouse gas emissions;
Establishes a joint industry-government partnership to research, develop and demonstrate new sustainable manufacturing and industrial technologies and processes; and
Authorizes FERC to pay employees with scientific technological, engineering and mathematical skills at a higher level than that allowed under civil service.
Renewable Energy
Extends incentives for hydroelectric production and efficiency authorized in the Energy Policy Act of 2005 through FY 2036;
Modernizes the Department of Energy’s R&D work on marine and hydrokinetic renewable energy; establishes the National Marine Renewable Energy Research, Development and Demonstration Centers at institutions of higher education;
Requires the U.S. Geological Survey to update its geothermal resource assessment; establishes a program to adapt oil and gas technologies for geothermal development; creates a prize competition for the production of critical minerals from geothermal brines; expands research into enhanced geothermal systems; establishes a research program for heat pumps and direct use; defines the thermal component of geothermal energy as renewable; and
Establishes solar and wind energy technology programs.
Energy Storage
Incorporates the Better Energy Storage Technology Act, establishing a research, development and deployment (RD&D) program to advance energy storage technologies; requires at least five demonstration projects; establishes a joint long-term demonstration initiative with the secretary of defense; facilitates a technical and planning assistance program for rural electric cooperatives and municipal utilities; directs FERC to issue a regulation on energy storage cost recovery;
Provides the secretary of the interior with sole authority for the development of pumped storage hydropower projects on Bureau of Reclamation reservoirs, eliminating the need for a separate permit from FERC; and
Creates a program on grid-scale energy storage to address challenges identified in the 2013 DOE Strategic Plan for Grid Energy Storage, including systems research, power conversion technologies research, grid-scale testing and analysis, and storage device safety and reliability.
Carbon Capture, Utilization and Storage
Establishes a technology program to improve the efficiency, effectiveness, costs and environmental performance of coal and natural gas use, including an R&D program, large-scale pilot projects, demonstration projects, and a front-end engineering and design program;
Establishes an RD&D carbon storage program, a large-scale carbon sequestration demonstration program and an integrated storage program;
Establishes an RD&D program to identify and assess novel uses for carbon, carbon oxide, carbon capture technologies for industrial systems and alternative uses for coal; and
Establishes a program to develop technologies for removing CO2 from the atmosphere on a large scale.
Nuclear
Replaces DOE’s existing Nuclear Energy Systems Support Program with a Light Water Reactor Sustainability Program to maximize the benefits of existing nuclear generation; enable continued operation of existing nuclear power plants through technology development; improve performance; and reduce plant operating and maintenance costs;
Creates a research program on next-generation light water reactor and advanced reactor fuels through FY 2025; and
Requires DOE’s Office of Nuclear Energy to develop a 10-year strategic plan that supports advanced nuclear R&D to help such reactors reach the market.
Vehicles
Creates a program of basic and applied research, development, engineering, demonstration and commercial application activities to increase the efficiency of, and reduce petroleum use in, passenger and commercial vehicles;
Creates a program of research, development, engineering, demonstration and commercial application for advanced vehicle manufacturing technologies and practices; and
Creates a program of cooperative research, development, demonstration and commercial application activities on advanced technologies for medium- to heavy-duty commercial, vocational, recreational and transit vehicles.
Natural Gas
Amends the Natural Gas Act to expedite approval of exports of small volumes of natural gas by deeming applications to export up to 51.75 billion cubic feet per year to any country to be consistent with the public interest;
Authorizes a study involving DOE and the secretaries of defense and treasury on the potential national and economic security benefits of building ethane and other natural gas liquids-related petrochemical infrastructure in the vicinity of the Marcellus, Utica and Rogersville shale plays.
Supply Chain Security
Updates the congressional declaration of policy on mineral security; and
Creates a program to develop advanced separation technologies for the extraction and recovery of rare earth elements and minerals from coal and coal byproducts.
Cybersecurity and Grid Security and Modernization
Amends the Federal Power Act to require FERC, working with DOE, NERC, the Electricity Subsector Coordinating Council and the National Association of Regulatory Utility Commissioners, to establish incentive-based rate treatments to encourage utility investments in advanced cybersecurity technology and participation in cybersecurity threat information sharing programs;
Establishes a competitive grant program for rural and municipal utilities to deploy advanced cybersecurity technology and participate in cybersecurity threat information sharing;
Authorizes financial assistance to help states develop energy security plans that assess states’ existing circumstances and proposes ways to improve its ability to secure infrastructure and minimize supply disruptions; reauthorizes the State Energy Program through FY 2025;
Requires DOE, working with state regulatory authorities, industry, the Electric Reliability Organization and other relevant federal agencies, to advance the physical security and cybersecurity of electric utilities, with priority provided to utilities with fewer resources; requires a report to Congress on improving the cybersecurity of electricity distribution systems;
Creates a program to develop advanced energy sector cybersecurity technologies and applications, and to leverage electric grid architecture to assess risks to the energy sector; requires DOE conduct “cybertesting” and mitigation to identify vulnerabilities of energy sector supply chain products;
Establishes a grant program for projects modernizing the electric grid, including distribution system technologies;
Establishes a program to promote hybrid microgrid systems for isolated communities and microgrid systems to increase the resilience of critical infrastructure; and
Creates a process to develop model grid architecture and a set of future scenarios to examine the impacts of different combinations of resources on the electric grid; the energy secretary would use the findings to determine whether any new standards are necessary for the grid, and if so, make recommendations.
Avangrid said this week it expects to begin construction this year on the New England Clean Energy Connect (NECEC) project to bring Canadian hydropower to Massachusetts despite a potential referendum on the project in Maine.
“We still expect to start construction in the third quarter of 2020 and start operation by the end of 2022,” CEO James P. Torgerson said on the company’s earnings call Tuesday.
Although most of the 145-mile New England Clean Energy Connect transmission line would follow existing utility paths (solid orange line), it would require removing trees for 53 miles through western Maine (dotted orange line). | Avangrid
Torgerson said the $950 million, 1,200-MW project won certification from the Maine Land Use Planning Commission on Jan. 8 and the state Department of Environment Protection’s final decision is expected in April, with the U.S. Army Corps of Engineers approval expected 60 to 90 days later. ISO-NE approval is expected in the first quarter.
A presidential permit, which is not needed to start construction but is to cross the border, is expected to be issued approximately 60 days after the corps’ and RTO’s approvals.
Although most of the 145-mile line would follow existing utility paths, it would require removing trees for 53 miles through western Maine. On Feb. 3, opponents of the project submitted more than 75,000 signatures to election officials, above the 63,000 signatures that must be certified to put the issue on the November ballot.
While opposition to the transmission project remains, “we have contributed resources for our political action committee, called Clean Energy Matters, dedicated to helping Maine voters understand the benefits of NECEC and correct misinformation about the project,” Torgerson said.
Earnings
Torgerson said the company was “very disappointed with our financial results, which were below our expectations.” The company reported net income of $700 million ($2.26/share) for 2019, compared to $595 million ($1.92/share) for the previous year. But adjusted net income for the year was $673 million, down from $684 million in 2018. In the fourth quarter, earnings were $223 million ($0.72/share) versus $119 million ($0.38/share) a year earlier.
But the company said it will benefit soon from higher rates in New York and Maine. Torgerson announced that the company would notify the New York Public Service Commission, in a letter filed Wednesday, that they had reached settlement in the New York State Electric and Gas and Rochester Gas and Electric rate cases.
“We recently received a final decision from the Maine Public Utilities Commission in the [Central Maine Power] distribution rate case and the metering and billing dockets,” Torgerson said. “Now our rate cases in New York and Maine represent about 55% of our total rate base with new rate plans going into effect this year. In Maine, it will be on March 1, and then in New York, it should be in May, depending on the settlement [that] we’re drafting now.”
Renewables
While the Renewables division continues with its onshore wind and solar growth, having completed 831 MW of projects last year and projecting 700 MW of new projects to be completed in 2020, the company also is looking offshore for future growth.
Avangrid is a 50/50 partner with Copenhagen Infrastructure Partners in Vineyard Wind, which has separate 800-MW offshore wind contracts with Massachusetts and Connecticut. It also controls a wind lease area off North Carolina in its own right.
The U.S. Bureau of Ocean Energy Management in February published a revised timetable for Vineyard Wind, with a final supplemental environmental impact study on Nov. 13 and the record of decision by Dec. 18. (See Offshore Wind Slogs Forward in Massachusetts.)
Vineyard Wind plans to use Bridgeport, Conn., as the primary port for construction, operations and maintenance on its 800-MW Park City offshore wind project. | Vineyard Wind
“Considering the revised base case, we target a commissioning date no earlier than 2023, [and] we also see no risk of the [power purchase agreement] termination under a later commissioning date,” Torgerson said. “The good thing is, with this later date, it will also help develop synergies with our Park City Wind. … Our Vineyard Wind joint venture was selected in Connecticut’s offshore wind [request for proposals] in December.”
In October, Vineyard Wind announced it had selected Marmon Utility to supply cables for the Connecticut wind farm. “Park City Wind has the potential to establish Bridgeport as an offshore wind hub,” Torgerson said.
Avangrid’s Kitty Hawk lease area off North Carolina, which has a potential capacity up to 2.5 GW, received Site Assessment Plan approval by BOEM on Feb. 20, he said.
Energy Secretary Dan Brouillette has named Alexander Gates to head the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER), according to an email from Brouillette obtained by E&E News.
He replaces Karen Evans, who has led the office since its creation in 2018.
Gates joins DOE from the National Security Agency, where he worked in intelligence analysis, cyber operations, cybersecurity, research and tool development. Gates also served at the department recently as the deputy director for cyber in its Office of Intelligence and Counterintelligence. In his email, Brouillette said Gates was chosen to strengthen the bond between the intelligence community and DOE.
Former Energy Secretary Rick Perry created the CESER office in September 2018 to pool the department’s cybersecurity resources and more effectively address online threats to energy infrastructure. Under Evans’ tenure, the office has helped coordinate responses by the Department of Homeland Security and states to manmade and natural disasters, including cyberattacks, electromagnetic pulses and geomagnetic disturbances.
In his email, Brouillette thanked Evans for her leadership on issues such as expanding the department’s data sharing efforts and overseeing responders following Puerto Rico’s earthquake this year. At the National Association of Regulatory Utility Commissioners’ Winter Policy Summit earlier this month, Evans praised states for stepping up their cybersecurity efforts, noting increased state participation in last year’s GridEx V. (See “DOE Praises State Cyber Efforts,” Cybersecurity, Resilience Talks Highlight NARUC Meeting.)
Before leading CESER, Evans was the national director of the U.S. Cyber Challenge, a program intended to promote cybersecurity talents. During the George W. Bush administration, she served in the Office of Management and Budget and later as chief information officer for DOE. Evans also worked with President-elect Donald Trump’s transition team preparing staff to take over OMB. Evans’ future plans have not been disclosed.
Burned by the GreenHat Energy default, PJM stakeholders appear to favor the RTO’s efforts to improve its risk evaluations of market participants. But some of the RTO’s proposed new procedures may face challenges before FERC.
During a daylong “page turn” of proposed Tariff and Operating Agreement revisions Wednesday, several stakeholders complained some of PJM’s proposed definitions are overly broad and said it seeks excessive authority to respond to credit risks.
The special meeting of the Markets and Reliability Committee covered language to implement rule changes approved by the Financial Risk Mitigation Senior Task Force (FRMSTF) in December. The RTO wants to bring the language to a vote of the MRC and Members Committee on March 26.
When task force members were asked whether they prefer changing the rules, all but four of 157 voters opposed the status quo (97%). But the proposed changes were approved on a more modest 101-57 vote (64%).
Wednesday’s session was an often tedious, occasionally fractious walkthrough of more than 100 pages of language changes in three sections of the OA and four sections of the Tariff.
Sparks flew early in the meeting when PJM officials refused to commit to accepting additional written comments, saying they wanted the meeting to be a “working session” to get stakeholders’ feedback.
“It’s very hard for us to provide comments on the fly,” said Noha Sidhom, of TPC Energy Fund, explaining that stakeholders might need to consult with their companies’ lawyers before taking a position. [Editor’s Note: Given an opportunity to review her quote per Manual 34, Sidhom said it was inaccurate but declined to say what was incorrect.]
“For PJM not to be upfront and not consider written comments, you’re setting yourself up for further delay and protests at FERC,” said economist Paul Sotkiewicz of E-Cubed Policy Associates, representing Elwood Energy. “It just leaves us feeling powerless.”
“That’s not my aim at all,” responded PJM facilitator Dave Anders. “I’m calling an audible. Let’s say we’ll accept written comments.”
But PJM Chief Risk Officer Nigeria Poole Bloczynski wasn’t willing to commit, citing concerns that some comments may be company-specific. “We haven’t said ‘no,’” she said, saying the decision on written comments would be made at the end of the session. “We want to make sure everyone hears the same thing.”
Sotkiewicz acknowledged Bloczynski’s concerns. “We’re not trying to have a one-on-one with PJM” through written comments, he said. But he said “from a due process standpoint, [rejecting written comments] doesn’t sound good. We can avoid a lot of that dust-up at the commission.”
PJM ended the meeting saying it would accept proposed changes to the language through Friday.
Facilitator Jen Tribulski said the proposed changes should be limited to changing terms “that you can’t live with” and not repeating issues raised during Wednesday’s session. “We would hope at this point that there’s not going to be a ton of redlines.”
“We want to reiterate: No comments,” Bloczynski said. “We’re looking for actual redlines.”
The MRC will hold another special session March 13, at which PJM staff will review changes made in response to the redlines or oral feedback.
‘Unreasonable Credit Risk’
There was no shortage of oral comments during the meeting, including frequent debate over whether the language was overly prescriptive or too vague.
Sotkiewicz complained that the rules would give PJM too much discretion to address what the rules call an “unreasonable credit risk,” noting that the term is undefined in the Tariff.
“There’s just too much latitude given to PJM to make calls on particular market participants,” he said. “It’s totally undefined and totally open to interpretation.”
Attorney Steve Huntoon, representing H-P Energy Resources, said PJM’s proposed changes to the term “market participant” could subject transmission customers and individual generators to burdensome reporting requirements.
He said stakeholders should vote against any change in the definition.
Anders responded by asking members to avoid advocacy over the coming vote. “We’re trying to work this out [collaboratively],” he said. “We’re trying to get it over the finish line so everyone can vote yes.”
At the end of the meeting, Tribulski promised PJM would address concerns that the term could apply to transmission customers. “We definitely heard the feedback,” she said. “So, we will tighten that up.”
‘Key Personnel’
PJM also received pushback on its plan to review whether an applicant to trade in PJM markets has “principal or key personnel in common” with a former member that has defaulted in PJM or other RTO/ISO markets.
Bob O’Connell of Panda Power Funds asked PJM to delete the term “key personnel,” saying if an individual is not an officer, “they’re not a key person.”
PJM attorney Jacqui Hugee disagreed, citing PJM’s experience with GreenHat, whose two principals had come to FERC’s attention for their roles in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the CAISO and MISO markets between 2010 and 2012. (See Doubling Down —with Other People’s Money.)
“If they go somewhere else and they’re not the principal of the company … I’d want to know that. … We want to know about these bad actors.”
O’Connell said he understood Hugee’s concern but worried about how applicants would meet the requirement. “Do I have to submit my full roster of employees?” he asked. “The issue is not the concept. The issue is the application.”
Sotkiewicz said PJM would be exceeding its authority by performing “ex ante enforcement.”
PJM attorney Steve Pincus said the RTO is using FERC guidance and trying to be practical: “It’s not productive to try to define every particular scenario,” he said.
Strategy Changes
Joe Wadsworth of Vitol challenged a requirement that market participants notify PJM of “material changes to [the company’s] business strategy.”
“I don’t see how that informs PJM on anything about the financial strength of an entity,” Wadsworth said. “It’s an overreach. At the end of the day, it’s the money. Do you have the money to support your position?”
Bloczynski said if a long-time financial transmission rights trader suddenly stops trading, “that’s noticeable. … We’re going to ask questions.
“Or you’ve acquired a new business … and will be participating in a different way,” she continued. “That’s something we’re going to want to know about.”
It’s okay for PJM to ask questions, responded Robert Viola, director of legal and compliance for Vitol. “The way this is written, if we don’t [disclose] it, we’re in breach of the Tariff.”
Anders said PJM will seek to address the concerns. “That sounds like a hot button for you,” he said.
The proposed rules include a table showing how PJM will determine a participant’s unsecured credit allowance based on parameters including the “internal credit score” assigned by the RTO. The credit score will be based on PJM’s evaluation of the companies’ profitability, liquidity and other measures.
Bloczynski said PJM would not make public its scoring model to avoid companies “manipulating their financials” to obtain a higher rating.
Jim Davis of Dominion Energy said PJM should rely on the ratings of external credit rating agencies where available, saying they are “very experienced” and “may have access to company personnel that PJM credit staff may not have access to.”
But Bloczynski said rating agencies’ gradings haven’t always been accurate, noting companies that were “rated investment grade and next day defaulted.”
Finding the Balance
Bloczynski also pushed back on some language changes, saying the existing terms — such as a reference to the “five most senior principals” — were added in response to earlier stakeholder requests for more detail.
She said PJM was seeking an appropriate balance. “We can be very prescriptive … and box ourselves in, or we can use some reasonable business practices, and that’s what we’re trying to do.”
The growth of distributed generation means the MISO grid will become increasingly fraught with planning challenges that require target responses, stakeholders heard Tuesday.
“We’re doing our best to adapt, and no one really knows what the future holds, but we can add more visibility into our planning processes,” MISO DER Program Director Kristin Swenson said during a joint workshop hosted by the RTO and the Organization of MISO States. The workshop was the latest in a series that the organizations have been hosting since 2017 to prepare for grid changes under widescale DER adoption. (See MISO Explores Changes to Accommodate DER.)
Swenson also said MISO is beginning to see improved coordination between transmission and distribution systems for planning purposes.
MISO contains about 4.5 GW of unregistered DERs in its footprint, according to an OMS survey completed last year. (See OMS: 4.5 GW of Unregistered DERs in MISO.) It also has about 16 GW in registered DERs participating in the market both in front of and behind the meter. For now, MISO’s definition of DER includes demand response and energy efficiency. RTO staff say its DER definition could change when FERC issues its own definition.
Iowa Utilities Board attorney David Schmitt said that a few MISO utilities with large penetrations of DERs in their territories have experienced backflow on the transmission system, though most have yet to experience any impacts.
| Alliant Energy
Swenson said the distribution system in some instances can provide a more attractive means of connecting to the grid for new, smaller generators than the MISO system, which is running out of capacity in the West region.
“We have folks who are frustrated with the MISO interconnection queue who turn to the distribution system. There is distribution capacity in some cases where there isn’t transmission capacity. … I can imagine that can provide a path to getting a project done that otherwise couldn’t be,” Swenson said.
DER experts said MISO should plan for an uneven adoption across the footprint, with some areas becoming hotspots of activity.
Stacy Van Zante, manager of delivery system planning for Alliant Energy, said her company’s Iowa subsidiary, Interstate Power and Light, contains about 204 MW of distributed generation, with 4,441 interconnections on the distribution system.
“In some areas, we don’t see a lot of distributed resources, but in other areas, what’s happening in Iowa is akin to California,” Van Zante said, describing neighborhood hotspots of solar adopters or projects on college campuses. “People are adopting at different rates.”
Planning for Every Hour
Van Zante said Alliant will examine the possible benefits of wind interconnections on the distribution system. If a distributed resource can benefit the surrounding system, the interconnection customer won’t bear the entire cost of the interconnection, she said.
She also noted Alliant has found that wind interconnections cause “wear and tear” on load tap changers on station transformers.
“We lived at the world of peaks, but that’s changing. There’s a lot of activity on the system,” Van Zante said, adding that Alliant is looking at the need for 8,760 hourlong load profiles for planning — one for each hour of the year.
“We want to avoid stranded investments,” she said.
Richard Mueller, DTE Energy’s manager of engineering technology, also agreed that planning is quickly evolving from peak loads.
“It’s changing the times we’re evaluating,” Mueller said.
John Schmall, of ERCOT’s Dynamic Studies Department, said the grid operator has tracked some of its DER influx by requiring distributed generators greater than 1 MW that plan to export energy into the distribution system to register with it.
However, he said ERCOT is still grappling with the challenges DERs can present to transmission planning, like accurate DER modeling and aggregation, and how to best represent unregistered DERs in planning and forecast their growth. He also said ERCOT is also studying DER impact on voltage recovery.
Schmall also agreed that peak times will become increasingly hard to predict.
“When you have a mix of solar and wind, and a diesel generator and energy storage, that’s something that will be a challenge in getting that information, to know when you charge and don’t charge. … There are big question marks that still need to be worked out,” Schmall said.
MISO currently makes DER penetration projections in the roughly 15-year future scenarios used in its annual Transmission Expansion Plan (MTEP), using estimates from Applied Energy Group, which is currently wrapping up updated DER forecasts for MTEP 20.
MISO will hold another DER workshop March 31 that will focus on DERs and how they could affect the RTO’s markets.
Consumers Energy on Monday announced it plans to achieve net-zero emissions by 2040, putting the utility on track to achieve that goal a decade earlier than most of its peers in the industry.
The announcement means the Michigan utility will aim to offset all carbon emissions created by the electricity it generates or purchases within two decades.
Consumers Energy CEO Patti Poppe in a Feb. 24 video released by the utility
In a release, CEO Patti Poppe admitted Consumers doesn’t have “all the answers yet” for reaching the goal but said it could counteract lingering emissions with “carbon sequestration, landfill methane capture or large-scale tree planting.”
Vice President of Public Affairs Roger Curtis said the move makes Consumers “the largest energy company in U.S. to plan net-zero this soon.”
“We have confidence in our ability to achieve that lofty ambition, though it’s about a decade earlier than most because of our Clean Energy Plan,” Poppe said in a video circulated by the utility. The Clean Energy Plan refers to the company’s 2019 integrated resource plan, which contains a goal to eventually meet 90% of Michigan’s energy needs with clean resources in addition to the new net-zero target. Consumers serves 6.7 million of the state’s almost 10 million residents.
“Consumers Energy is proud to take a stand for Michigan and for the planet. We are committed to take actions that eliminate our carbon footprint and do our part to combat climate change,” Poppe said. “Our Clean Energy Plan already is focused on protecting the planet, and our net-zero pledge takes that commitment to the next level.”
Consumers previously committed to an 80% reduction in carbon emissions from 2005 levels by 2040, a goal shared by Michigan’s other large utility, DTE Energy.
But the two companies now appear to be headed in different directions.
While DTE in 2018 announced it would strive for net-zero carbon emissions by 2050, its most recent IRP was recently sent back for major changes by the Michigan Public Service Commission, which ruled DTE hadn’t properly accounted for the benefits of renewable generation and relied too much on existing coal and natural gas generation. (See Michigan PSC Orders DTE to Redo IRP.)
Consumers, on the other hand, received approval in June for an IRP that proposed eliminating its coal fleet and reducing emissions from power plants by 90% by 2040. The company plans to retire the D.E. Karn plant in 2023 and idle Units 1 and 2 at its J.H. Campbell plant as early as 2025, replacing them with energy efficiency, solar and wind farms, and battery storage. The utility has already retired seven coal-fired power plants.
Fading Love for Coal
Poppe, who herself held positions at DTE until 2010, has been uncharacteristically candid for a utility CEO about Consumers’ obligation to cut emissions to mitigate the effects of climate change and her changing attitude toward coal-fired generation. She has repeatedly admitted she once dismissed climate predictions as alarmist.
“On that last day at every facility … it’s a heart-wrenching sort of day because of the effect and the change that’s happening to the people there,” Poppe said of attending coal plant closures on a Feb. 18 edition of the podcast “Illuminators,” which chronicles transformation and disruption in the energy industry.
“But you know, my co-workers are very proud of what they’ve done — as they should be — and very realistic and customer-centric to say that we care about our future generations and we care about making sure that we can, at the end of our days, look back and say that we did everything that we could to protect future generations from the effects of climate change.
“That just supersedes … in these tough decisions. But on the day of, you can bet, it’s a tough day for the people who are so deeply affected by the change,” Poppe said, who also admitted to once having a bumper sticker on her electric car that read, “I love coal.”
She told the Illuminators’ host that she’s since swapped it for a pink sticky note on her wall that reads, “I used to ‘heart’ coal.”
“I do think that coal had its time and place, and now we have the really great fortune that the economics have changed. We’ve got other clean energy technologies that can help us in ways that were not possible before. … We used to have this sucker’s choice: You can have clean energy — it’s just going to be expensive. Or, you can have the cheap and dirty stuff. Take your pick. We sold that story for a long time, and the reality is we don’t have to make that sucker’s choice anymore,” Poppe said.
Two MISO planning committees are set to begin discussions on what the RTO can do to break down walls between the annual Transmission Expansion Plan and network upgrade planning for the generation interconnection queue.
Speaking during a Coordinated Planning Process Task Team conference call Monday, MISO Senior Manager of Economic Planning Neil Shah revealed a list of transmission planning topics to be divided between the Planning Subcommittee and Planning Advisory Committee.
The task team has been compiling ways MISO could increase consistency between its MTEP and queue processes since January. Stakeholders have suggested that the RTO better align the timelines of MTEP and interconnection planning and ensure their respective studies draw on more similar data, including dispatch assumptions. The synchronization effort could have MISO approving more transmission projects by MTEP 21. (See MISO Seeks Ideas for Streamlined Tx Planning.)
Stakeholders also suggest MISO link its annual transmission planning process with network upgrade planning. Renewable proponents and some state regulators have repeatedly said the RTO is unfairly relying on interconnection customers to finance increasingly expensive new transmission capacity under the pretext of network upgrades and may be neglecting a responsibility to get major transmission projects approved in its transmission packages. Renewable advocates have questioned why interconnection studies show the need for expensive transmission upgrades when MTEP studies do not.
The PSC will review the study objectives, methodologies and modeling assumptions behind existing MISO reliability planning, economic planning, transmission service requests, and generator interconnection and retirement processes.
Once it compares the processes, the PSC may choose to make changes to certain methodologies and modeling assumptions to “ensure comparable treatment,” according to MISO.
The PAC will be tasked with the remainder of the possible planning overhaul, including devising a process for study coordination and data exchange to help MISO’s planning processes identify transmission needs “that are common to generator interconnection, reliability planning and economic planning process.”
The committee will also explore how it might design a multipurpose project designation for the Tariff that combines aspects of generation interconnection, baseline reliability and/or market efficiency projects.
Finally, the PAC will scrutinize the timing behind reliability planning, economic planning and generator interconnection processes to see how they can better align project evaluations to ensure that a recommended transmission upgrade receives the most precise project designation.
“If we coordinate and exchange information across the three planning processes, instead of us pursuing different, smaller upgrades in different processes, we have an opportunity to recommend a bigger, better project that can take care of multiple issues,” Shah said, referring to MTEP planning and necessary network upgrades identified in the generation interconnection queue.
“We could be laying the groundwork for how we restructure project categorization,” Wisconsin Public Service Commission economist Enrique Bacalao said.
Bacalao said the “natural evolution” of the PAC and PSC discussion could be that MISO reorganizes its planning processes so that “certain projects have more than one component to them” and are cost allocated accordingly.
Clean Grid Alliance’s Natalie McIntire asked why MISO’s list didn’t include the possibility of a consolidation of the generator interconnection and MTEP planning processes.
“We could potentially see that merging the processes could be helpful,” McIntire said.
That move could be on the table, Shah said, but MISO doesn’t want to prescribe any action at this point by specifically directing the PAC to consider it.
Shah said he will brief the issues list to more stakeholders at the PAC’s March 11 meeting. Multiple stakeholders thanked Shah for capturing the nuanced issues in the to-do list.
HARTFORD, Conn. — Lawmakers will this continue to focus this legislative session on efforts to transition the state to renewable energy and a carbon-neutral grid by 2040 while protecting ratepayers who already pay the highest electric bills in the continental U.S., industry participants heard Monday.
Leaders of the General Assembly’s Energy and Technology Committee spoke to about 100 members of the Connecticut Power and Energy Society (CPES) and the state’s bar association at the University of Connecticut School of Law. The meeting came a month after Connecticut regulators convened a public hearing to examine whether ISO-NE’s wholesale electricity markets are effective in serving the state’s clean energy objectives. (See Connecticut Weighs Pros, Cons of ISO-NE Markets.) Public Utilities Regulatory Authority (PURA) Chair Marissa Gillett attended the discussion but did not comment.
“I think we’re going to try to continue and build on the successes that we had last year in our two major pieces of legislation, offshore wind and HB 5002,” said Rep. David Arconti (D), the committee’s co-chair, referring to a bill (HB 7156) authorizing the procurement of up to 2 GW of offshore wind and another authorizing procurement of energy derived from anaerobic digestion.
“A lot of our colleagues like to talk about energy in terms of what are we doing to address climate change, but when you get into the weeds of energy policy, it gets much more difficult to navigate those waters because there are so many other factors you have to consider,” Arconti said. “The top two obviously for me leading this committee are utility costs and the reliability of the grid.”
“One of the things we do as legislators is try to stand on the cutting edge of technology and bring forward those policies that are going to help Connecticut, but at the same time look out for our ratepayers,” said Rep. Charles Ferraro (R), one of the ranking members on the committee.
“We’re very focused on moving us to a more renewable future, and Gov. Ned Lamont’s initiative for a carbon-free grid is something we’re trying to turn into policy in a reasonable way, knowing that Connecticut already has the highest electric rates in the country,” said Sen. Norm Needleman (D), co-chair of the committee. “Advancing that agenda without breaking the backs of people and businesses who live here is the dancing on the head of a pin that we’re trying to do.”
As for offshore wind, Needleman said Connecticut is uniquely positioned with two deepwater ports, Bridgeport and New London, which do not have bridges separating the piers from the open water.
“Connecticut has the opportunity to be a leader and the location for a lot of offshore wind deployment,” Needleman said.
Tech and Tax Solutions
Sen. Paul Formica (R), the other ranking member, could not attend Monday’s discussion but was quoted in The Connecticut Examiner in January as favoring energy storage as a solution to the variability of solar and wind.
Formica said he is “working with leaders in the energy sector on the mechanics of a bill that will incentivize the creation of ‘pockets’ of megawatt storage along the transmission line, which could prevent blackouts during major weather events,” the Examiner reported.
Arconti said, “The goal of the bill is to bring the storage industry here to Connecticut, and storage is how we’re going to solve the intermittency issues of renewable energy.”
He said the legislation will contain “a very ambitious goal” of 1,000 MW of energy storage by 2030 “to mirror some of the programs we have with the offshore wind.” Lawmakers will also ask PURA to “leverage all the great work they’ve been doing on the grid modernization dockets, specifically the energy storage section,” he said.
Needleman brought up the need to tax commercial solar developers who he thinks enjoy an unfair property tax break on solar arrays between 1 and 5 MW, in many cases to the detriment of rural communities.
“I believe that the threshold at which we levy property tax is way too high, and a lot of those power plants are benefiting wealthier communities,” Needleman said.
He said he is working on legislation that would lower the tax threshold for commercial generation and would base the property tax only partly on project location in order to prevent developers from avoiding taxes.
Speaking about non-wires alternatives, microgrids and distributed energy resources, Needleman said he is “a big fan” of DER but thinks a microgrid powered by natural gas would conflict with public policy given the “big push to restrict the amount of natural gas we are using moving forward.”
“I have not been a huge fan of the state rushing headlong one way and now trying to do a gigantic reversal of policy that was put in place the last decade,” Needleman said. “It doesn’t make a lot of sense to set public policy with radical shifts. I think we need to be sensible. … We need realism, not just aspirational policy.”
NRG Energy on Thursday reported 2019 income from continuing operations of $4.1 billion, compared to $460 million for the previous year, the large difference driven by the release of a $3.5 billion tax valuation allowance. Adjusted EBITDA was almost $2 billion, up from almost $1.8 billion in 2018.
