FERC is taking another look at its April orders approving the cost allocations for a stability fix for New Jersey’s Artificial Island nuclear complex and an upgrade of the Bergen-Linden Corridor.
The commission issued orders June 21 granting rehearing — a technical step to allow it more than 30 days to reconsider complaints that PJM’s use of the solution-based distribution factor (DFAX) cost allocation method is inappropriate for the two projects (EL15-95, ER15-2563 and ER15-2562, et al.).
In the case of the Artificial Island project, the public service commissions in Maryland and Delaware, along with some transmission owners, complained that the customers they represent will bear the brunt of the cost of the fix while receiving a small percentage of load savings.
Similarly, Consolidated Edison and Linden VFT disputed the fairness of the Bergen-Lindon Corridor upgrade cost allocation.
“We know this is only one step in the process of continuing to fight the current proposal, but we are encouraged by the opportunity to again make the case to FERC that the current cost allocation scheme is both unjust and unreasonable,” Delaware Gov. Jack Markell said in a statement.
TransCanada last week filed a formal arbitration request under the North American Free Trade Agreement, seeking $15 billion in damages for President Obama’s rejection of its Keystone XL Pipeline project.
NAFTA’s arbitration rules allow companies to challenge government decisions before international panels. TransCanada had filed a notice of intent in January and tried to negotiate a settlement with the U.S. government.
The company said it is seeking to recover its costs, calling Obama’s decision “symbolic and based merely on the desire to make the U.S. appear strong on climate change, even though the State Department had itself concluded that denial would have no significant impact on the environment.”
ETRACOM Fined $2.5M; Will Seek Federal Court Review
ETRACOM and its principal trader Michael Rosenberg said they will seek a de novo review in federal court of FERC’s June 17 order fining them $2.5 million and demanding repayment of $315,000 in unjust profits (IN16-2).
The commission concluded the company submitted uneconomic virtual supply transactions at the New Melones intertie at the CAISO border to affect power prices and benefit its congestion revenue rights in 2011. The commission ordered the company and Rosenberg to pay the fines within 60 days. Chairman Norman Bay, who headed the Office of Enforcement during part of the commission’s investigation, did not participate in the order.
ETRACOM insists it used a legitimate bidding strategy at New Melones based on hydro conditions. In a press release, it said FERC’s order was “the result of an unfair and arbitrary process, wrong on the merits and largely rubber stamps the views of its Enforcement staff.” It said it “is confident that a neutral decision maker will decide it committed no wrongdoing.”
White House: Coal Program Costs Taxpayers Billions
A White House study of federal coal leases concluded that the U.S. government is probably losing $3 billion of revenue a year because of permissive rules and loose oversight.
“Companies have employed several tactics to lower the selling price of coal without losing revenue,” according to the report by the White House Council of Economic Advisors. Mining companies sell coal to affiliates at low prices or levy penalties from utilities that reject deliveries. In those instances, the government doesn’t receive its share. “The program has been structured in a way that misaligns incentives going back decades,” the report states.
The U.S. is supposed to collect a 12.5% royalty on coal mined from federal land but is actually receiving closer to 5%, according to the report.
Sen. Maria Cantwell (D-Wash.) is urging FERC to take special actions to make sure an expected natural gas shortage on the West Coast doesn’t lead to market manipulation.
In a letter to FERC Chairman Norman Bay, Cantwell said the Aliso Canyon leak could lead to increased electricity and gas prices and enable companies to “engage in Enron-like tactics.”
“Westerners still remember 2000-2001,” Cantwell wrote. “History must not be allowed to repeat itself.”
The Federal Emergency Management Agency said officials who participated in a recent test for Nebraska’s Cooper Nuclear Station are ready to work together in the event of a disaster at the plant.
The test, conducted June 14, probed how well Missouri and Nebraska agencies, organizations and the utility itself would react to a crisis involving Cooper, which is owned and operated by the Nebraska Public Power District. The exercise is a biennial requirement that measures adequacy of state and local radiological emergency readiness and response plans.
“It was a very productive event,” said Chuck Gregg, a senior planner with FEMA. “There’s a lot of good things that came out of this.”
The lower house of Germany’s legislature passed a measure that will ban fracking in clay formations and issue more stringent rules governing fracking in deeper formations.
The legislation bans fracking in clay formations, which normally lie between 1,000 and 2,500 meters deep. The ban would be reviewed in 2021. Energy companies, however, say exploring the country’s shale gas reserves would guard against the country growing more dependent on natural gas imports, which mostly come from Russia.
Lawmakers have been mulling an amendment that would allow shale fracking under 3,000 meters and had asked companies to hold off on their projects until they finalized the details. They moved quickly to pass the ban, however, after a report that companies were growing impatient and moving ahead. Fracking is deeply unpopular among the German populace.
The Nuclear Regulatory Commission ruled that the operators of the shuttered Vermont Yankee are permitted to shrink the plant’s emergency operations, denying a request from Vermont officials that Entergy reinstate the same standards used when the plant was operating.
Entergy retired the plant in December 2014. Since then, it has reduced personnel at the emergency operations center and successfully lobbied NRC to erase the standard 10-mile emergency planning zone.
The commission said the state didn’t provide evidence to support its arguments that the reduced emergency plan failed to account for all credible emergency scenarios and posed an increased risk to the health and safety of citizens.
FERC: Redesign Overlapping Pipeline Routes in Ohio
FERC told the developers of two competing Appalachian natural gas pipelines that they have to redesign an overlapping 13-mile section of their routes in Ohio before it can consider approving them.
The Rover and Leach XPress pipeline projects, planned by Energy Transfer Partners and Columbia Pipeline Group respectively, “are proposed in exactly the same location” with construction planned for “the same calendar year.”
FERC said it wants a response from the companies within 10 days of the June 21 letter. The Rover pipeline is planned to run 700 miles through West Virginia, Pennsylvania, Ohio and Michigan, while Columbia’s Leach Xpress is to run 130 miles from West Virginia, through Pennsylvania and into Ohio.
NEW YORK — Scott Weiner, the New York Public Service Commission’s deputy for markets and innovation, discussed the state’s Reforming the Energy Vision initiative.
“REV distinguishes itself not by its specific proposals but by its comprehensiveness. If you take a look at the specific components of REV, most, if not all, are being tested or applied somewhere else in North America. What we’ve tried to do is pull them all together at one time in a holistically, comprehensively approach to reform.”
Kerry Stroup, manager of state legislative and regulatory affairs for PJM, discussed the challenges of introducing any systemwide programs to the RTO, which operates in 13 states and D.C.
“Innovation is something that happens in a different way in a multi-jurisdictional entity like PJM as opposed to a single unit like New York or Ontario. … PJM is a market maker and doesn’t implement policy. So that can be a challenge at times because those state retail regulatory frameworks range from vertically integrated utilities to hybrid models to entire fully restructured retail markets.”
Peter Fraser, vice president of industry operations and performance for the Ontario Energy Board, said previous market models are inadequate to address customer preferences for cleaner energy and the increased integration of newer technologies.
“We’re changing the way electricity is priced to consumers in a number of ways, with residential rates going to a fixed monthly charge for their electric distribution rates. [We’re] studying reforms to nonresidential rates, and we issued a discussion paper this spring that recognizes the changes that are ongoing in the electric distribution market.”
Aleck Dadson, vice president of consultant StrategyCorp and former COO of the Ontario Energy Board, said the board embarked on a redesign of its market in advance of REV that was influenced by regulatory changes in Europe, particularly the U.K. It included a wide deployment of smart meters and increased renewable energy penetration.
“There is a really strong emphasis on performance measurement. We established scorecards that are customer-focused, with customer service metrics, operational effectiveness, safety, reliability, public policy responsiveness,” he said. “And the board every year publishes a scorecard to compare the distribution companies, to see who’s doing well and who isn’t.”
FERC on Friday approved an amendment to SPP’s bylaws clarifying that the RTO should not credit assessments for transmission service over and above the amount of members’ monthly administrative fee.
But the commission said the RTO improperly clawed back overpayments last year based on its reinterpretation of its bylaws before the rules were officially changed, ordering the RTO to pay $1.6 million in refunds (ER16-829).
SPP collects its administrative costs through a monthly assessment applied to load eligible to take network service under its Tariff (Schedule 1-A fees). Members receive a credit against the monthly assessment for fees paid for serving their load with network or point-to-point transmission service.
Between 2003 and 2015, the RTO had been making credits that sometimes exceeded the 1-A fees, with the RTO providing credits against other portions of the customers’ transmission settlement statements. The excessive credits resulted in a 1% undercollection of its administrative fees annually, forcing SPP to charge a higher administrative rate in the subsequent years.
In March 2015, SPP staff reinterpreted its bylaws and capped the credits. In December, the Board of Directors approved a revision of section 8.4 of the bylaws to clarify the new practice.
FERC approved the new crediting policy effective March 30, 2016, but denied SPP’s request for a waiver allowing the RTO to apply it retroactively.
As a result, the commission ordered SPP to provide refunds within 30 days for credits it denied last year under its new interpretation. The ruling was a victory for 13 SPP members who received credits in excess of their monthly assessments during 2014. Two members who filed protests, Kansas City Power and Light and Nebraska Public Power District, will receive the majority of the refunds, a combined $1.2 million as of December.
DETROIT — Four industry executives and a state regulator shared their views on distributed generation, resource adequacy and aging infrastructure during a stakeholder panel at the MISO Annual Meeting last week.
Robert Gee, of Gee Strategies Group, moderated.
Melody Birmingham-Byrd of Duke Energy Indiana called distributed energy resources an “inevitability” and said her company is embracing the change with “heavy involvement” in research and projects.
However, she said designing a DER rate structure remains a concern. “We want to make sure those who can afford distributed resources aren’t doing it on the backs of those that can’t,” she said.
Teresa Mogensen, senior vice president of transmission at Xcel Energy, said the grid “is a long, long way from being dead” and will continue to play a role even with greater use of distributed generation.
“We do have customers that have disconnected from the grid, and if they’ve done that, more power to them,” said DTE Electric President and COO Trevor Lauer. He said his company will be aided in its transition to DER by new, younger workers: DTE Energy will turn over 50% of its workforce over the next seven years, he said.
Jennifer Vosburg, senior vice president of NRG Energy’s Gulf Coast region, said customers “aren’t waiting around: The utility of the future is here. Our concern is, can the markets keep up, can the regulation keep up, can it be integrated into the market system?”
Michigan Public Service Commission Chairman Sally Talberg said she didn’t know how soon distributed resources would permeate the grid. “I have a National Geographic from 1983 that says solar is the way of the future,” she joked.
Resource Adequacy Concerns
All of the speakers expressed concerns over MISO’s ability to attract new generation to replace retiring plants.
“Right now, it’s hard to see how an independent power producer [without] a power purchase agreement could build new generation,” Lauer said.
Vosburg said MISO hasn’t implemented anything to “trigger new investment.”
The panel also addressed the growth of natural gas and its history of price volatility.
“Who would have thought seven years ago that there would be such a fundamental change in electric generation with fracking and natural gas use?” Lauer said. “I think price volatility is going to be there, but I think the larger concern is infrastructure and gas storage.”
Talberg agreed and said pumping gas through pipelines in Michigan can be “high-risk” since some pipelines are “vintage.”
The panel generally agreed that the Clean Power Plan stay isn’t going to slow progress on emission reductions.
“Our concern is the rate and pace of carbon emission [reductions], not that we’re going down that path,” Birmingham-Byrd said. “What Duke Energy is trying to do while [we] retire coal plants is to have a more diverse generation portfolio.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
PJM Manuals (9:10-10:00)
Members will be asked to endorse the following manual changes:
Manual 7: Protection Standards. Clarifications were recommended by the Relay Subcommittee as part of its biennial review of the manual.
Manual 10: Pre-Scheduling Operations. Changes make clear that reporting rules for all outages apply to both capacity and energy resources.
Manual 14B: PJM Region Transmission Planning Process. Updates light load and winter peak reliability analyses to align with current practices, among other updates.
Manual 15: Cost Development Guidelines. Clarifications are the result of a periodic review. Adds Tariff-approved language regarding pumped storage hydro units.
Manual 18: PJM Capacity Market. Changes are the result of a periodic review; conforming changes relate to Capacity Performance and the “deploy all resources” action.
The committee will be asked to endorse changes to make the parameter-limited schedule exception process more flexible. (See “More Flexible Parameter Limited Exception Process Approved,” PJM Market Implementation Committee Briefs.)
Members will be asked to elect Gary Greiner of Public Service Enterprise Group as a Transmission Owner sector representative. He will take the place of PSEG’s Frank Czigler, who has left the company.
AUSTIN, Texas — To address the Defense Department’s frustrations over Texas’ lack of regulation for siting new generation, the governor’s office is working with ERCOT to require notifying the department of proposed projects that might impact military operations.
DeAnn Walker, a senior policy adviser in Gov. Greg Abbott’s administration, told a Gulf Coast Power Association luncheon audience that she’s been working on the issue for nine months. Military issues are a top priority for Abbott, she said.
The Pentagon’s main concerns have been wind turbines disrupting radar signals and solar panels causing glare for pilots. Used to working with states who have control over siting facilities, military officials have been frustrated with Texas’ system, which lacks any state-level oversight. “The military claimed there were times when the first time they knew about a wind turbine farm going up near their facility was when they started seeing the turbines built,” she said.
Walker said concerns have been raised over projects planned around naval air stations in Corpus Christi and Kingsville. She knew of only one generation project canceled because of a conflict with military operations.
Walker worked with ERCOT to develop PGRR 47, which was presented in May. The change to ERCOT’s Planning Guide would require developers seeking interconnection approval to report on the status of reviews by the Pentagon and the Federal Aviation Administration.
A luncheon attendee pointed out that the military already receives notification about projects from FAA, which can occur much sooner than the interconnection application.
In exchange for its cooperation, the state has asked the Defense Department to provide color-coded maps that show where developers might run afoul of military siting restrictions, Walker said. The maps would be of all military operating areas in the state and be marked green (where there are no restrictions), yellow (where they could work together toward a solution) and red (where the military would oppose any development). Another attendee said the maps already exist on FAA’s website.
Walker said Abbott is adamant about winning approval of the change and asked that anyone with concerns address them with her directly.
Although the lack of siting regulation has caused tensions in Texas, the Defense Department has worked cooperatively with the power industry, becoming early advocates of renewables and microgrids.
At a FERC technical conference on reliability earlier this month, Chris Murray of the Navy’s Renewable Energy Program Office invited transmission and generation projects onto naval facilities. “If there is land on our base that you think makes sense, let us know. And more often than not, that land is going to be behind a secure perimeter with guards, which also can be good for a critical asset,” he said.
DETROIT — MISO expects the use of technologies such as energy storage, synchrophasors and HVDC lines to increase, Executive Vice President of Transmission and Technology Clair Moeller told the Board of Directors at its System Planning Committee meeting last week.
“As we do modeling into the out years … we see a substantial shift in the footprint away from coal — and that’s expected. But how the rest of the mix [develops] plays an important role,” Moeller said. “It’s a pretty interesting time in terms of how the portfolio might shift.”
Synchrophasors, which provide real-time transmission data, can answer whether “you can safely take the system to its physical limits to completely squeeze all you can out of the grid.” Moeller said. “This is the electric system’s introduction into big data.”
“How much [capacity] is in [the transmission system]? Because you know it’s there,” board member Paul Bonavia said. “This is a lot of food for thought.”
Board member Michael Evans asked if MISO could commission a technology company “that’s already slogging through the big data” to analyze the RTO’s information.
HVDC
MISO has found that DC transmission, which is ideal for transporting large amounts of power over long distances, only becomes as cost effective as AC for lines longer than 600 miles.
Moeller said DC technology could connect MISO resources to ERCOT and the Western Interconnection.
“If there are technologies available to us to move power from Denver to Des Moines, direct current is the way to go,” he said.
Clean Line Energy is MISO’s largest DC merchant, with three interconnection projects in the queue: the Grain Belt Express (which could carry 4,000 MW of wind power from western Kansas to Missouri, Illinois and Indiana), the Rock Island line (3,500 MW of capacity from northwest Iowa to Illinois) and the Plains & Eastern line (4,000 MW of capacity from the Oklahoma Panhandle to Tennessee and Arkansas). The Plains & Eastern project faces opposition from Arkansas’ congressional delegation. (See House Panel OKs Bill Targeting Clean Line Project.) MISO has just three DC lines to date: one in Manitoba and two transferring power from North Dakota into Minnesota.
“They’re substantially faster and more flexible,” Moeller said.
Storage
MISO’s treatment of battery storage as generation will have to change, Moeller said. It cannot be “force fitted” into a generation market definition, he said.
Although energy storage is evolving rapidly, and utilities are beginning to experiment with it, it is not yet competitive in MISO, Moeller said. He said there is no an independent source that has identified when storage will become economically viable.
Moeller also said MISO believes storage’s competitiveness has been hurt by the low cost of gas. While storage technology becomes cheaper and MISO shifts from its dependence on coal, Moeller said the RTO has discussed strategies to more precisely model price volatility, including securing grants for Ph.D.s in university mathematics departments for a more complex algorithm for gas prices and renewables. MISO currently uses U.S. Department of Energy data and simple inflation to forecast gas prices.
MISO Vice President of System Planning and Seams Coordination Jennifer Curran said the RTO expects installed gas capacity to increase in the near future, with 2,700 MW of gas-fired generation projects in advanced stages of study in the generator interconnection queue.
By 2030, MISO expects gas penetration to reach 35%, almost equal to coal’s current 36% share.
MISO said the substantial shifts in generation mix is justification for the RTO to begin making its own independent load forecasts.
Two generation owners on Friday petitioned FERC to block New England states’ efforts to have electric ratepayers underwrite the cost of expanded natural gas pipelines (EL16-93).
NextEra Energy and Public Service Enterprise Group said the proposals by state regulators to release natural gas capacity to electric distribution companies “will render ISO-NE markets unjust, unreasonable and unduly discriminatory, and result in manipulation of the ISO-NE market.”
The generators asked FERC to rule by Aug. 23 and order ISO-NE to draft a “prophylactic tariff fix” within 90 days. They also seek a technical conference and “final” FERC order by the end of January 2017, before the next Forward Capacity Auction in February.
“State regulators in Massachusetts, New Hampshire, Connecticut and Rhode Island are on the verge of implementing a scheme expressly intended to artificially suppress prices in wholesale energy markets in New England,” the companies wrote.
“Having no use for the pipeline capacity, the EDCs would release the capacity at below-market rates — first to gas-fired generators … and then whatever is left will be released to the marketplace,” the complaint continued. “This transportation subsidy would artificially flood ISO-NE markets with gas, thereby unreasonably suppressing gas prices and wholesale power prices.”
The proposal by the EDCs, endorsed in varying stages in proceedings by state regulators, would allow the distributors to recover from their ratepayers the cost of access to expanded pipelines.
EDCs Eversource Energy and National Grid favored the capacity release proposal at a FERC technical conference held last month. (See Utilities Seek OK for Gas Releases to Generators at Technical Conference.) The two are partners in the proposed Access Northeast pipeline at the center of the dispute. It would bring shale gas from the Marcellus region of Pennsylvania into New York and New England.
The Massachusetts Department of Public Utilities, which is the furthest along among the regulators, has ruled such a contract is legal under state law. It is considering a proposal for a 20-year gas supply contract that could be approved as early as October. (See More Pipelines for New England: ‘Gold-plating’ or Necessity?)
Massachusetts Attorney General Maura Healey has supported a lawsuit filed by ENGIE and the Conservation Law Foundation that challenged the legality of such contracts. A ruling by the state’s Supreme Judicial Court is expected soon.
Another proposed pipeline that could have benefited from ratepayer subsidies, Kinder Morgan’s Northeast Energy Direct, was scuttled earlier this year, in part because of the lack of commitments for firm capacity customers. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)
PJM is opening its second competitive project proposal window of the year this week.
Its scope consists of a year 2021 analysis of N-1 and N-1-1 thermal and voltage contingencies; generation deliverability and common mode outages; and load deliverability thermal and voltage.
The window will be open 30 calendar days, PJM said. Those offering proposals during that time will be permitted 15 additional days to submit detailed greenfield reports.
This is the second window for which a new proposal fee will apply for upgrades and greenfield projects. There is no fee for proposed projects costing less than $20 million. A $5,000 fee will be assessed for projects of up to $100 million. Proposals with a projected cost of more than $100 million must be accompanied by a $30,000 fee.
Details on registering were presented at the January Planning Committee meeting.
In the case of the Artificial Island project, the public service commissions in Maryland and Delaware, along with some transmission owners, complained that the customers they represent will bear the brunt of the cost of the fix while receiving a small percentage of load savings.
ETRACOM and its principal trader Michael Rosenberg said they will seek a de novo review in federal court of FERC’s June 17 order fining them $2.5 million and demanding repayment of $315,000 in unjust profits (
A White House study of federal coal leases concluded that the U.S. government is probably losing $3 billion of revenue a year because of permissive rules and loose oversight.
The Federal Emergency Management Agency said officials who participated in a recent test for Nebraska’s Cooper Nuclear Station are ready to work together in the event of a disaster at the plant.
The Nuclear Regulatory Commission ruled that the operators of the shuttered Vermont Yankee are permitted to shrink the plant’s emergency operations, denying a request from Vermont officials that Entergy reinstate the same standards used when the plant was operating.
NextEra Energy and Public Service Enterprise Group said the proposals by state regulators to release natural gas capacity to electric distribution companies “will render ISO-NE markets unjust, unreasonable and unduly discriminatory, and result in manipulation of the ISO-NE market.”