FERC on Friday granted NERC’s request for more time to submit changes to its Rules of Procedure (ROP) ordered by the commission in January (RR19-7).
The revisions demanded by FERC on Jan. 23 in response to the ERO’s five-year performance assessment include updating terminology regarding the Electricity Information Sharing and Analysis Center; providing greater transparency in its sanction guidelines; and making various improvements to its certification program. (See NERC Wins Another 5 Years as ERO.) FERC ordered NERC to make a compliance filing by July 21 confirming the changes.
On Feb. 21, NERC asked the commission to extend the deadline for the compliance filing to Aug. 28, a delay of more than a month. Moving the deadline would “ensure transparency in developing revisions to the ROP,” NERC said, by allowing it to follow a “more feasible” schedule for its review process, which requires a 45-day stakeholder comment period and review by the Board of Trustees before its next meeting. Under the extended timetable, the board will have until the Aug. 20 meeting to review the changes, rather than May 13.
NERC said the extension will also let it perform FERC’s changes in conjunction with an ongoing project to revise the ROP regarding the registration and certification program, with input from regional entities, stakeholders and the Compliance and Certification Committee. The organization said a longer deadline would let it “present a complete set of registration and certification ROP revisions” that are also in compliance with the commission’s order.
In its response, FERC accepted the organization’s reasoning and said NERC would be “granted an extension of time to and including Aug. 28, 2020,” to comply with the order.
FERC’s January order also required NERC to make a compliance filing by April 22 providing any audits it has conducted of the REs during the five-year period or a plan for performing them within the next 18 months. (See NERC Seeks More Time on Rule Changes.)
SEATTLE — The Western Electricity Coordinating Council should zero in on issues specific to the Western system when it sets its near-term priorities for 2021 and 2022, stakeholders told the regional entity at a Feb. 20 reliability workshop.
Utah Public Service Commissioner Jordan White, newly appointed chair of the Western Interconnection Regional Advisory Board (WIRAB), lauded NERC’s work last year in identifying the four broad “risk profiles” the Electric Reliability Organization must address in the near term.
They included the rapid transformation of the grid, threats from extreme natural events, security vulnerabilities and the interdependency of critical infrastructure across different sectors. Each category encompasses more specific challenges, such as those related to bulk system planning, resource adequacy, situational awareness and cyber threats. (See ‘Interdependencies’ Joins RISC’s List.)
“While WIRAB believes all of those risks are truly important and should be addressed in some fashion by the industry, ERO, governments [and] the public at large, WIRAB really took those risk profiles and used two simple criteria to prioritize those risks” for WECC’s purposes, Jordan said during the workshop.
The first criterion: “Does the risk have a uniquely Western view on it compared to other areas in the ERO?” Jordan said.
The second: What is WECC’s ability to make an impact, given its authority and expertise both internally and through its stakeholder committees?
Using those lenses, WIRAB compiled its own list of WECC priorities, which include focusing on resource adequacy and performance, the changing resource mix, the increasing complexity in control systems and extreme natural events.
On the resource adequacy issue, White pointed to recent Northwest Power Pool analysis that shows that the Northwest and Northern California could begin to experience shortages as early as this year and will face capacity deficits in the “thousands of megawatts” by the middle of the decade. A report by consulting firm Energy and Environmental Economics last year warned that without new dispatchable resources, the broad region could see a capacity shortfall of about 8,000 MW by 2030. (See NW Price Spike a ‘Wake-up Call,’ ex-BPA Chief Says.)
“With recent announcements and current decommissionings in place for some of the baseload generation in the Desert Southwest, the resource adequacy issue will become more widespread across the interconnection as we go forward through this decade,” White said. “It’s for that reason [that] decision-makers [and] policymakers are really looking for a transparent, unbiased set of data projections as they go forward in making decisions” around resource planning.
WIRAB’s focus on the changing resource mix is driven by the increasing number of entities pursuing low-carbon or carbon-free goals. While Utah has a noncompulsory renewable portfolio standard, White said some communities in the state have adopted their own carbon-free goals for 2030, part of a pattern that’s taken hold across the West.
“It’s not just necessarily the states [adopting carbon policies]; it’s corporations; it’s renewable buyers; it’s municipalities,” he said.
“And with that change in resource mix … the challenges we’re facing now are increased variability [and] lower system inertia,” White said.
WIRAB’s concern over the increasing complexity in control systems stems from the growth of distributed energy resources.
“With the changing resource mix that I’ve discussed, the distribution system has become more dynamic. We’ve got new loads, resources … and more complex control systems. … As the line between transmission and distribution continually fuzzes, that is an increasingly important area to focus on,” White said.
White emphasized the importance of the Institute of Electrical and Electronics Engineers’ standard 1547-2018, which requires DERs be able to perform grid-support functions. It was recently endorsed by the National Association of Regulatory Utility Commissioners. (See State Regulators Endorse IEEE DER Standard.)
Without appropriate settings for inverter-based DERs, WIRAB has determined that voltage disturbances in Southern California could propagate as far north as Oregon and Utah.
“We’re all connected together,” White said.
“With more inverter-based [resources] being added to the system every day, it is increasingly important to understand that interplay” between the distribution and bulk systems, he said.
WIRAB’s concern about extreme natural events is understandable given the series of devastating wildfires that have ravaged California in recent years, leading utilities there last year to increasingly rely on the unpopular policy of public safety power shutoffs (PSPS).
“Public safety power shutoffs are really one tool to reduce the risk of electrical equipment sparking [wildfires], but obviously these shutoffs pose hardships on customers,” White said.
To provide context around the sheer scale of disruption from PSPS, White noted that the Southwest blackout of 2011 affected about 2.7 million customers in Southern California and Arizona, with most seeing restoration within six hours.
“By stark comparison, in 2019, when the California [investor-owned utilities] conducted their shutoffs, that impacted roughly the same amount of customers; however, those customers were without power for an average of 2.1 days, and in some extreme cases, customers endured [shutoffs] for close to a week,” he said.
White added that nobody has studied the potential impact of PSPS on the rest of the West. “Obviously, [the IOUs’] customers are in California, but how might that eventually create a cascading event throughout the interconnection?” he asked.
Keeping the Lights on
WECC’s Member Advisory Committee also counseled the RE to keep a tight focus on issues particular to the West.
MAC Vice Chair Brenda Ambrosi, BC Hydro’s market policy and operations manager, laid out a set of “fun facts” about WECC, which covers 14 U.S. states, two Canadian provinces and the northern tip of Baja California, Mexico.
“Five of these states have the lowest temperatures [in the U.S.]; four states have the highest temperatures,” Ambrosi said. “Ten locations are the driest and sunniest. Six locations are the cloudiest. Five locations are the snowiest. The Western Interconnection has the most and least humid locations.
“What I’m trying to do is conjure up a picture in your mind of how unique and interesting the Western Electricity Coordinating Council region is, with respect to its topography, and how different it is from the rest of the ERO,” she said.
Acknowledging that the region must pay attention to universal industry issues such as cyber threats, Ambrosi advised WECC zoom in on the physical threats — from both weather and sabotage — to the “high-impact nodes” often located in remote, hard-to-reach areas.
“With all of these threats being out there and our uniqueness, the MAC thinks that we need to focus a little bit more on the physical threats, and we need to protect those extremely critical and valuable assets in our region,” she said.
Ambrosi said the California shutoffs are “a big impact and happening more and more.”
“We need to realize that these events are not only impacting the bulk electric system but the distribution system as well,” she said.
She said the MAC believes WECC “needs to work with regulators and policymakers to highlight the serious reliability repercussions [of PSPS] and try to find better solutions, rather than just turning off the lights.”
MAC Chair Russ Noble, reliability compliance manager with Cowlitz County Public Utility District in Washington, came at the interplay between the BES and the distribution system from a different angle — that of the growth of behind-the-meter solar.
“The interdependency between the BES and the distribution system is becoming more and more of a factor and is complicating the ability to keep the BES running smoothly,” Noble said. The MAC believes that regulators and policymakers have overlooked the importance of the distribution to BES reliability.
“We have standards for the BES, but we don’t have them for the distribution system, and we need to consider coordinating a reliability program” between the two systems, he said.
The MAC also asked WECC “to encourage regulators and policymakers to consider reliability impacts of resource retirements and stability challenges of inverter-based resources,” Noble said.
Head in a Bag
A “walk-around” exercise provided some flavor of the opinions of the workshop’s 80 in-person participants (20 more people dialed in). Attendees were encouraged to circulate throughout the conference room and read posters with descriptions of NERC-identified risks, then stand next to the posters containing the topics they felt WECC should prioritize.
A large group clustered around the “Resource Adequacy and Performance” poster. WECC’s Matt Elkins spoke on behalf of the group, saying participants expressed concerns about “everybody planning to go to the market at the same time. If that’s how they think they’re going to be resource-adequate, that could be a wrong assumption — if everyone’s trying to buy the same energy.”
But the biggest group by far gathered around the “Changing Resource Mix” poster. CAISO’s Sarah Garcia took to the microphone to explain this group’s thinking, saying, “We really think that this is the umbrella issue that affects or drives a lot of these others, or is driven by a lot of these others.”
Because the resource mix is changing more quickly than the industry ever anticipated — and in such high volume — “there are unintended consequences of what we put into place now because we just can’t foresee the future,” Garcia said.
She noted that a fellow group member had quipped that it’s “like we’re driving into the future with a bag over our head.”
Garcia took the joke further: “I think what’s really happening is that we’re driving into the future with a bag over our head, and our car has [an unpredictable] fuel source, and increasingly the car is going to be made of a thousand tiny drones with bags over their heads and unknown fuel sources.
The standard drafting team working on expanding options for entities to manage bulk electric system cyber information (BCSI) (Project 2019-02) is focusing on resolving overlaps both within the affected standards and with other ongoing projects. It hopes to post the proposed standard for final ballot by July 2020.
Participants at this week’s SDT meeting in Phoenix took aim at several recurring themes in industry comments on the draft proposals for standards CIP-004-7, covering cybersecurity personnel and training, and CIP-011-3, covering information protection. One of the most pressing topics of discussion was the perception that the project was expanding beyond its original remit; this was amplified by the SDT for Project 2019-03, which expressed concern that 2019-02 might touch on areas covered by its mandate to tackle cybersecurity supply chain risks, including revising CIP-013.
Supply Chain Conflict Ironed out
“We have … met several times with the CIP-013 team. I think we have a way forward on how to [address] any duplication with our standards and CIP-013 risk assessment,” said SDT Chair John Hansen, of Exelon.
The conflict between the teams centers on language in CIP-011-3 concerning cloud storage providers that might be used by responsible entities. Under the most recent proposal, the standard would require entities to perform initial risk assessments of vendors when they first contracted with them and follow-on assessments every 15 months. However, the proposal for CIP-013-2 also includes a requirement for entities to perform risk assessments on third-party service providers, leading to fears of contradiction between the two standards.
| Shutterstock
In a compromise, the 2019-02 SDT agreed to remove the language mandating risk assessments and replace it with a requirement that entities “implement one or more documented BES cyber system information risk management method(s)” to address data governance and rights management; protection of relevant cyber information; data sovereignty and transformation; physical and personnel security; certification; and business agreements. Members of the team for 2019-03 said the change would make the two standards complementary.
“My first gut reaction here is that this is something that might be in combination with what’s in CIP-013. In CIP-013, you’re actually looking at the vendor, but with [2019-2] you’re … doing risk management on … how are they going to protect your data,” Tony Hall of LG&E and KU said. “To me this seems completely different than what we saw the first time, so I give you guys credit for that.”
Team Seeks Clarity on Location Requirements
Other changes to CIP-011-3 in response to industry comment include removing requirements for processes to “authorize access to BES cyber system information based on need” and to “identify applicable BES cyber system information storage locations.” These requirements were originally part of the proposal for CIP-004-7 but were moved to CIP-011-3 because the SDT felt they focused on information security. However, after reviewing industry feedback, team members decided to keep them with the personnel- and training-focused CIP-004 for the sake of clarity.
“It might have been a small misstep for us when we added the BCSI location section to [CIP-011-3],” said Vice Chair Josh Powers, of SPP. “It seemed to conflict with what we were trying to do. It made sense, probably, at the time, but I think it does run into the philosophical difference [with] where we’re headed.”
The drafting team plans to make further modifications to the proposal at its next in-person meeting March 17-19 and submit the proposal for quality review by the beginning of April. Once quality review is completed, the standard will be posted for additional comment from May 7 to June 21, with the final ballot in July. NERC’s Board of Trustees will consider the proposal for adoption at its meeting on Aug. 19 in Vancouver, Canada.
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.
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.
