In a final rule issued Jan. 9, FERC has increased its maximum civil penalties by 1.6% to reflect inflation.
The rule revised commission fines for violations of FERC-jurisdictional statutes, rules and orders imposed under the Federal Power Act, the Interstate Commerce Act, the Natural Gas Act and the Natural Gas Policy Act of 1978. FERC is required to make the annual update under the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (RM17-9).
Inflation was calculated using the U.S. Department of Labor’s Consumer Price Index for all urban consumers, comparing October 2016 figures with those from October 2015.
The new set of maximum fines range from $1,270 per offense, per day for violating the Interstate Commerce Act to $1,213,503 per violation, per day for violating sections of the Federal Power Act, the Natural Gas Act or the Natural Gas Policy Act.
The rule becomes effective upon publication in the Federal Register. FERC submitted the rule to the Senate, House of Representatives and Government Accountability Office and posted it without notice and comment period because it did not exercise discretion over the inflation calculation.
ERCOT rang in the new year by breaking an 18-day-old record for winter electricity demand six times within 14 hours, thanks to an early-January Arctic front that brought sub-freezing temperatures to Central Texas.
Demand reached 59,650 MW during the 6 p.m. interval on Jan. 6, smashing the previous winter record of 57,924 MW set Dec. 19. The record was topped five more times before 9 a.m. the following morning.
ERCOT had forecast a winter peak of 58,591 MW.
The new winter peak easily surpassed the previous January record of 57,256 MW recorded in 2014.
December peak demand was up 29% year over year, with the short-lived record far exceeding the 44,934-MW monthly peak seen a year earlier.
Last month marked the fifth straight month the Texas grid operator set a new record for monthly peak demand, dating back to August. Electricity consumption was up 11.2% in November, while the previous three months were all up less than 4%.
Overall, the ERCOT system produced 351.5 million MWh of electricity in 2016, just above the forecast of 350.6 million MWh.
VALLEY FORGE, Pa. — When Dominion Resources argued that failing to build a 500-kV line across the James River could result in blackouts, opponents of the plan didn’t believe it.
It turns out the company wasn’t bluffing.
Ronnie Bailey, a transmission planner for Dominion, presented the company’s alternative plan at PJM committee meetings this week, saying that the closure of its two coal-fired Yorktown plants in April will create a “long list” of N-1-1 contingencies that could result in voltage collapse and thermal overloads on the Virginia Peninsula.
An N-1-1 contingency represents the consecutive loss of two elements in a power system but with intervening time for operator adjustments.
The plan — the North Hampton remedial action scheme (RAS) — would be armed at PJM’s discretion. If the RTO detects the loss of certain facilities, it would trip the remaining feeds to the Yorktown area and drop service to approximately 150,000 customers, preventing voltage collapse. Rotating outages would follow until the facilities are repaired. Bailey confirmed the RAS has been approved by the SERC Reliability Corporation.
The blue circle depicts the area that will be affected by blackouts if Dominion’s RAS for North Hampton is utilized.
The Surry-Skiffes Creek line was proposed to maintain grid reliability on Virginia’s Lower Peninsula after Dominion shutters the Yorktown units. Increased environmental regulations have made the units impractical to run, and the isolated peninsula has few other power stations. With the local load projected to grow 8% by 2020, Dominion saw increasing the area’s connection to the grid as the only viable solution.
The project has attracted opponents, who are concerned that the transmission line would ruin the view at Jamestown and other historic sites nearby and believe the blackout warning is a scare tactic. A study conducted on behalf of the National Parks Conservation Association concluded that Dominion overestimated projected power growth and called for consideration of other alternatives, including underwater lines and converting the Yorktown plants to natural gas.
Approved by the PJM Board of Managers in 2012, the transmission project remains stalled pending permit approval from the U.S. Army Corps of Engineers. Bailey estimated that construction of the line would take at least a year after all permits are approved.
At a Jan. 11 Market Implementation Committee meeting, PJM Independent Market Monitor Joe Bowring asked Bailey if he was “100% certain” the Yorktown units would close. Bailey would only say that they’re required to close by law.
The region is home to numerous large electricity customers, including Newport News Shipbuilding, Joint Base Langley-Eustis, the Yorktown Naval Weapons Station, NASA, Historic Jamestowne, Colonial Williamsburg and the College of William and Mary.
Bailey assured the committee that the RAS “is only a stopgap measure,” noting that PJM’s regulations require those schemes to be temporary responses.
New York Gov. Andrew Cuomo has proposed the development of 2,400 MW of offshore wind generation off Long Island by 2030, the largest commitment to that energy source in the U.S.
Cuomo said the roadmap for developing offshore wind projects will be laid out in a master plan to be completed by the end of the year.
New York last year adopted a Clean Energy Standard that commits the state to generating 50% of its electricity from renewables by 2030.
The offshore wind commitment would provide enough power for 1.25 million homes and projects would be built out of view of onshore communities, according to Cuomo.
The announcement came a day after the governor took credit for the early closure of the Indian Point nuclear plant north of New York City by 2021, although plant owner Entergy cited low natural gas prices as the reason for shuttering the facility. (See Entergy to Shut Down Indian Point by 2021.)
Cuomo said a combination of transmission upgrades, energy efficiency and new renewable energy resources would replace lost generating capacity from Indian Point. Still, other clean energy sources would be needed to fill the gap before an adequate volume of offshore wind production could be put in service.
One proposed project 30 miles southeast of Montauk Point, the first phase of the massive Deepwater ONE project, would deploy about 90 MW of offshore generation by 2022.
The governor called on the Long Island Power Authority to approve that project, which has been stalled for months. State energy officials last summer requested a delay in project negotiations just as an agreement appeared to be in sight, and the agency’s board of directors failed to take up an expected vote on the project in December. (See LIPA Delays Vote on Offshore Wind Project; 90-MW Project Would be Largest in US.)
But Cuomo’s statement indicated that the project could be back on track, with the board now expected to consider a contract with the developer at its Jan. 25 meeting.
The project’s developer, Deepwater Wind, operates the nation’s first offshore wind farm off the coast of Rhode Island.
The governor’s proposal also calls on state agencies to ensure environmentally sensitive development in a 79,000-acre federally leased area capable of siting about 800 MW of offshore wind off the Rockaway Peninsula. The project area 17 miles south of the peninsula was the subject of a federal auction in December, which attracted a record $42.5 million bid by Norwegian energy company Statoil Wind US.
Cuomo said agencies should work with affected stakeholders — such as fishermen, maritime industries, coastal communities and labor groups — to ensure proper development.
He also directed the Department of Environmental Conservation and the New York State Energy Research and Development Authority to undertake a comprehensive study to determine the most rapid, cost-effective and responsible way to reach 100% renewable energy for the entire state.
“Gov. Cuomo’s plan to build 2,400 MW of offshore wind power by 2030 makes New York a national leader of this new clean energy industry,” Liz Gordon, director of the New York Offshore Wind Alliance, said in a statement. “The governor’s powerful endorsement will spur billions in investment, create thousands of skilled jobs and generate clean, affordable and reliable electricity for New York.”
She added: “The myriad benefits of offshore wind power have attracted the vocal support of a broad, diverse and growing coalition that unites business, labor, environmentalists, developers, academics, community leaders and environmental justice advocates.”
Environmental groups last month called on Cuomo to commit to developing offshore wind off Long Island.
“We applaud Gov. Cuomo for listening to New Yorkers and committing to large-scale, long-term offshore wind in New York and moving New York’s first offshore project forward,” said Lisa Dix, senior New York representative for the Sierra Club.
FERC has affirmed a previous ruling stating that evidence of price reporting deficiencies by power sellers during the Western Energy Crisis of 2000-2001 cannot constitute the sole basis for a finding of market manipulation during the event.
The commission’s Jan. 9 order clarified a key element of an October 2016 decision that gave credence to California’s contention that a failure of some power sellers to file compliant price reports with FERC may have helped conceal market manipulation, which in turn created a “pricing umbrella” under which California’s Department of Water Resources was compelled to sign overpriced contracts near the conclusion of the crisis (EL02-71). (See FERC to Consider Western Energy Crisis ‘Umbrella Pricing’ Theory.)
That decision opened the door for the California parties to the ongoing proceeding — which include the Public Utilities Commission, the state’s attorney general’s office, Pacific Gas and Electric and Southern California Edison — to introduce evidence of reporting deficiencies as part of the examination of factors that enabled sellers to charge the state exorbitant contract rates.
The October ruling prompted Shell Energy North America, TransCanada Energy and Hafslund Energy Trading, collectively referred to as the “indicated respondents,” to ask the commission to affirm a previous finding that “evidence supporting a pricing umbrella argument cannot in and of itself establish liability” for any sellers still involved in the energy crisis proceeding.
“Out of an abundance of caution, indicated respondents respectfully seek clarification and confirmation of the commission’s ruling,” the companies said in a November 2016 filing with the commission.
The three companies said that they assumed the commission would only permit the introduction of pricing umbrella evidence as a means to “provide greater context and depth to actual probative respondent-specific evidence regarding the California parties’ claims for remedies against respondents.”
Pricing umbrella evidence would not in and of itself represent such probative evidence, the companies contended.
“Therefore, for example, no pricing umbrella evidence can alleviate the California parties’ burden to establish that a reporting deficiency ‘masked an exercise of market power or other overt manipulation [by a respondent] in order to demonstrate the required nexus between an unlawful act and an unjust and unreasonable rate,’” the companies said, citing the commission’s previous finding.
FERC’s Jan. 9 order confirmed the companies’ understanding of how the pricing umbrella theory will be applied in the proceeding.
The order notes that the commission will “continue to find that evidence of a third party’s conduct [in filing deficient reports] is not relevant to this showing because the focus of the Mobile-Sierra inquiry [into the contracts] is the conduct of the seller and whether that conduct directly affected contract prices.”
That language echoed the commission’s previous determination that evidence of a reporting violation alone could not overcome the Mobile-Sierra presumption of the “justness and reasonableness” of a contract. Such a finding would require evidence of an actual intent to manipulate markets.
“We clarify that, while we will permit the introduction of pricing umbrella evidence solely for the purpose of providing greater context and depth for probative, seller-specific evidence, this evidence should not be treated as evidence that can be the basis of a finding of refund liability,” the commission said. “We thus affirm that pricing umbrella evidence is not an element upon which a finding of refund liability may be based in this proceeding.”
Massachusetts legislators last week passed a bill that seeks to remove barriers to electric vehicle ownership and allows utilities to invest in charging infrastructure.
Gov. Charlie Baker is expected to sign the bill, which moved through the legislature last year but was left out of an omnibus energy bill that addressed several clean energy items. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.) The bill passed in the legislature’s informal session, a day before the start of the regular session.
| Mass
The new law prohibits charging station operators from requiring subscription fees from EV drivers and allows towns to create EV-only parking spaces. It also codifies regulations that would allow cost recovery for utilities’ EV infrastructure and promotes studies of issues such as the electrification of the state vehicle fleet.
The bill additionally requires “fair” rates for public charging, a detail that will be left to state regulators to determine.
Supporters said the final bill eliminated a provision directing the state Board of Building Regulations and Standards to amend building codes in order to require that new residential and commercial buildings be pre-wired for EV charging — instead leaving that as a recommendation.
“Massachusetts consumers want electric cars, but convenient access to charging stations is a barrier to getting more electric vehicles on the road,” said Megan Herzog, staff attorney at the Conservation Law Foundation. “This bill helps communities promote the charging infrastructure necessary to support increased electric car sales in the state.”
Herzog noted that transportation is the single largest contributor to Massachusetts greenhouse gas emissions. The sector is responsible for nearly 40% of in-state emissions, making their reduction crucial to meeting the targets of the state’s Global Warming Solutions Act.
“We must be mindful of our greenhouse gas emissions, especially those emitted by our transportation sector,” Senate President Pro Tempore Marc R. Pacheco (D), cosponsor of the bill, said in a statement. “We need to lessen our dependence on fossil fuels and make it easier for owners of electric cars to use their vehicles while incentivizing the transition to zero-emission transportation.”
Mark LeBel, a staff attorney at Acadia Center, said the bill’s provision to allow utility investment in charging station infrastructure codifies language from an existing Department of Public Utilities order.
“The specifics of utility proposals will be important to determine whether the three statutory criteria for approval are met,” LeBel said. “The proposals must be in the public interest, meet a need regarding the advancement of EVs and must not hinder the development of a competitive EV charging market.”
The Baker administration recently committed $14 million to the Massachusetts Offers Rebates for Electric Vehicles (MOR-EV) program, which offers state residents rebates of up to $2,500 for qualified vehicles.
FERC has approved PJM’s proposal for selling back excess capacity in this February’s third Incremental Auction for the 2017/18 delivery year.
The commission, however, agreed with objectors on several points, prompting it to require key revisions to the plan (ER17-335).
“While we acknowledge deficiencies in PJM’s filing … we also agree with PJM that it is just and reasonable for PJM to alter the shape of its sell-back offer curve to a straight line, eliminating the potential that the relevant Incremental Auction could clear at or near $0/MW-day,” the commission said.
The proposal dealt with PJM’s transition to the Capacity Performance market construct, which was approved in 2015 and gradually implemented over the 2016/17 and 2017/18 delivery years. The RTO had already obtained capacity for those years under previous rules, so the approval also established two transition auctions to procure any additional capacity needed.
The transition auction for the 2017/18 delivery year saw the RTO procure 10,017 MW of previously uncommitted capacity. PJM holds three IAs following the initial Base Residual Auction for a specific delivery year, during which committed capacity resources can buy back their supply obligations and PJM can acquire or release capacity in response to updated load forecasts. The IAs for the transition years also covered the results of the transition auctions.
The methodology PJM used for releasing excess capacity from the 2016/17 delivery year resulted in 4,818 MW sold at an average price of $4.79/MW-day, and PJM warned that using the same process to release any of the 10,017 MW for 2017/18 would potentially result in an offer of $0/MW-day — with no money flowing back to load.
To better reflect the capacity’s value, the grid operator proposed an alternative approach that would identify any necessary changes to the amount of capacity the RTO had already procured and create a price curve for selling any excess.
FERC modified PJM’s proposed sell-back curve for excess capacity for the 2017/18 Delivery Year to top out at the BRA clearing price for that year.
PJM additionally proposed that any excess that doesn’t sell at the auction would not be eligible to become excess-commitment credits. PJM creates the credits from excess capacity that doesn’t clear IAs and allocates them to load-serving entities, who can trade them or use them to replace existing capacity requirements. (See “Proposal Chosen for Capacity Release,” PJM Markets and Reliability and Members Committees Briefs.)
FERC approved PJM’s plan but ordered several changes in recognition of objections made by American Municipal Power. The commission directed PJM to revise the price curve so that it begins at the lowest price point on the current sell-back offer curve and ends at the BRA clearing price for that delivery year. It also ordered allocating uncleared excess capacity as excess-commitment credits and consolidating separate capacity sellbacks into the single auction.
“Performing two auctions in this manner will result in creating two prices for the same product in the same auction, without any justification for the different price,” the commission said.
FERC clarified that the approved changes to the sell-back procedure only apply to the third IA in February.
PJM Independent Market Monitor Joe Bowring was surprised the commission put so much effort into what he felt was a minor detail, but he was still disappointed that his office hadn’t intervened in the docket. During discussions to secure stakeholder endorsement of PJM’s proposal, the Monitor repeatedly objected to the plan.
The Western Area Power Administration and Sacramento Municipal Utility District (SMUD) have extended the scoping period for a proposed transmission line intended to increase SMUD’s ability to import power from the Pacific Northwest and export from the Sacramento area.
The scoping period for the Colusa-Sutter (CoSu) line will be extended an additional 60 days, from Jan. 6 to March 7, to elicit public comment on environmental issues related to the proposed project, which would create a new 500-kV link between the California-Oregon Transmission Project (COTP) and SMUD and WAPA facilities on the east side of the Sacramento Valley.
The proposed Colusa-Sutter transmission project is intended to improve SMUD’s access to Pacific Northwest renewable resources via the California Oregon Transmission Project. | WAPA
Federal power marketing agency WAPA sells power to publicly owned utilities such as SMUD, but its existing transmission facilities do not have enough capacity to meet SMUD’s increasing need for energy, the agency said. The new line would connect the COTP system in Colusa County with the Central Valley Project system in Sutter County, improving access to renewable energy generated in the Northwest.
“A recent California Energy Commission study makes the case for projects like this that enhance transmission capability to import valuable out-of-state renewable resources for California to meet its 50% renewable energy goals by 2030,” WAPA and SMUD said in a statement.
WAPA and SMUD said the project will provide additional bidirectional transmission capacity to improve SMUD’s ability to participate in CAISO’s Western Energy Imbalance Market (EIM).
The extended scoping period for the line will include review of an additional study area located about 20 miles south of the three other study areas previously scoped over the past couple years. The newly considered corridor would connect to the COTP in Yolo County and terminate near the Elverta Substation in northwestern Sacramento County, crossing directly into SMUD’s service territory.
“The new study area will help us make a more informed choice about how to best meet our future energy needs, while minimizing impacts on the environment and surrounding communities,” said Kim Crawford, SMUD’s California Environmental Quality Act project manager.
Six public meetings about the line are planned for January and February. Comments received during the meetings will be considered in the preparation of the draft environmental impact report. Any other comments must be submitted by March 7.
WAPA said it will take no action on the proposed project until after the environmental review is completed in 2020.
When the Obama administration released its first version of the Quadrennial Energy Review two years ago, it addressed a hypothetical concern about threats to the nation’s oil and natural gas pipeline infrastructure.
The second review from the Department of Energy, released last week, turned its attention to risks facing the nation’s electric grid — progressing from the hypothetical to the real.
“In the current environment, the U.S. grid faces imminent danger from cyberattacks,” the report said. “Widespread disruption of electric service because of a transmission failure initiated by a cyberattack at various points of entry could undermine U.S. lifeline networks, critical defense infrastructure, and much of the economy; it could also endanger the health and safety of millions of citizens.”
The review is especially timely, coming amid a national discussion about the possibility that cyber breaches influenced the 2016 presidential election. It noted examples of such attacks in the electricity sector, including attacks on three Ukrainian utilities in December 2015 that left 200,000 customers without power, and highlighted the need to take decisive action to enact protections.
The report called for using the Federal Power Act to “develop preparation and response capabilities that will ensure [FERC] is able to issue a grid-security emergency order to protect critical electric infrastructure from cyberattack,” as well as from natural threats such as geomagnetic storms.
Graphic illustrates the many ways in which utility IT systems leave the electricity grid vulnerable to cyber attacks, including unpatched networks, exposure to the public internet and insider threats.
The department also calls for an expansion of FERC authority to modify NERC-proposed reliability standards or develop its own standards “to protect national security in the face of fast-developing new threats to the grid.”
FERC’s expanded role in developing grid safety standards would supplement the department’s efforts at implementing protective measures in times of emergency.
“This approach would maintain the productive NERC-FERC structure for developing and enforcing reliability standards but would ensure that the federal government could act directly if necessary to address national security issues,” the report said.
“FERC should consider having existing regional organizations undertake such planning, as it deems appropriate,” the review said. “FERC should evaluate whether the costs of implementing security measures identified in the integrated electricity security plan are appropriate for regional cost allocation, where such measures are found to enhance the security of the regional transmission electric system.”
However, the department would not saddle grid operators with full financial responsibility for fulfilling the recommendations. Noting that the cost of protecting the nation’s grid against cyberattacks could run as high as $500 billion, the report calls for federal assistance in the form of an expanded DOE loan guarantee program used to encourage innovative grid technologies, going beyond the current emphasis on loans for new generation methods.
“A relatively low-cost permanent federal financing system could be established by setting up a revolving loan fund with one-time seed capital,” the report states. A loan guarantee program would be crucial for smaller utilities that lack the access to capital, unlike larger companies.
In all, the 494-page report makes more than 70 recommendations for policymakers to consider. It remains to be seen how many will be undertaken. The first QER outlined 63 recommendations — 21 of which were enacted by Congress.
PJM announced that its comprehensive analysis and recommended solution for issues related to Artificial Island won’t be ready until April.
Staff had expected to present the plan at the February meeting of the RTO’s Board of Managers.
“While PJM’s analysis is progressing well, during discussion of preliminary results with stakeholders, several questions and considerations were raised,” PJM’s Steve Herling said in an emailed announcement. “More time is needed to evaluate and respond to these questions and considerations.”
Following complaints over cost allocation and a near doubling of the estimated costs, the board suspended the Artificial Island project, PJM’s first Order 1000 competitive solicitation, pending a “comprehensive” staff analysis to be completed by next month. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
PJM presented preliminary results of its analysis at its Planning Committee meeting in December and concluded that several elements of the scope of work would change. Stakeholders raised concerns about the changes and questioned whether PJM planned to re-evaluate all of the proposals in light of the updated criteria. Herling said at the time that the RTO was only “realistically” focused on the finalists. (See “PJM Review of Artificial Island Bid Elements Completed,” PJM Planning/TEAC Briefs.)
Independent Market Monitor Joe Bowring characterized the decision as a “tough call” and said the extra two months “is not that big a deal.”
The rule revised commission fines for violations of FERC-jurisdictional statutes, rules and orders imposed under the Federal Power Act, the Interstate Commerce Act, the Natural Gas Act and the Natural Gas Policy Act of 1978. FERC is required to make the annual update under the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (RM17-9).
