A Wyoming federal judge’s ruling last week striking down the Obama administration’s regulations on fracking on federal lands will save operators about $113,000 per well, according to an industry-sponsored analysis.
The study, which was performed by John Dunham & Associates at the request of the Western Energy Alliance, found that the regulations by the U.S. Bureau of Land Management would have added at least $403 million annually to well development costs.
The regulations would have affected several thousand wells each year on federal and Indian lands, either as new drilling or maintenance of existing wells. The majority of the lands are in western states and the Gulf of Mexico.
Wyoming, Colorado, Utah, North Dakota and the Ute Indian Tribe challenged the regulations in a case that was combined with a separate suit by WEA and the Independent Petroleum Association of America.
The regulations, which were to take effect in June 2015, were stayed pending the outcome of the case.
While the breakdown between oil and gas wells was unclear because federal statistics don’t separate them, U.S. Energy Information Administration data show that the average cost to develop a natural gas well has been steadily rising to more than $600/foot as of 2007, which is the most recent information the agency provides. EIA reported the average total well cost at nearly $4 million.
Fossil fuel production on federal and Indian lands, FY 2014 Source: U.S. Energy Information Administration based on U.S. Department of the Interior, Office of Natural Resources Revenue.
In his ruling, U.S. District Judge Scott Skavdahl explicitly avoided the question of whether or not the regulations are necessary and instead focused entirely on BLM’s authority to enact them (Case Nos. 2:15-CV-043-SWS, 2:15-CV-041-SWS).
Dismissing the agency’s arguments that it has jurisdiction through several tangential regulations, Skavdahl searched for specific delineation of authority from Congress. He found that the Safe Drinking Water Act requires EPA to adopt requirements for state programs to prevent underground injection from threatening drinking water sources.
He also cited the Energy Policy Act of 2005, which expressly excluded federal oversight of fracking that doesn’t involve diesel fuel.
Skavdahl rejected BLM’s argument that the generalized authority the agency cited would supersede the more specific SWDA and EPACT.
“Given Congress’ enactment of the [Energy Policy] Act of 2005, to nonetheless conclude that Congress implicitly delegated BLM authority to regulate hydraulic fracturing lacks common sense,” he wrote. “Congress’ inability or unwillingness to pass a law desired by the executive branch does not default authority to the executive branch to act independently, regardless of whether hydraulic fracturing is good or bad for the environment.”
The administration filed an appeal on Friday. “We believe that we have a strong argument to make about the important role that the federal government can play in ensuring that hydraulic fracturing that’s done on public land doesn’t threaten the drinking water of the people who live in the area,” White House spokesman Josh Earnest said during a press briefing on Wednesday.
NEW YORK — Whether the view is from PJM, which sits atop the Utica and Marcellus shale gas formations, or ISO-NE, at the “end of the pipeline,” the so-called “dash to gas” shows no sign of abating, speakers said Friday at the Energy Bar Association Northeast Chapter’s 2016 Annual Meeting.
“There’s a fairly high degree of confidence in the market that gas prices will be consistently low for a fairly long time,” said Vince Duane, senior vice president and general counsel at PJM. Of 36,000 MW of PJM generation that has retired in the last two decades, about 30,000 MW of the units replacing them are natural gas, he said.
Duane said that while the energy industry has “done a very poor job of forecasting prices and deploying capital” in the past, “the markets are [now] giving such an overwhelming signal” to choose gas.
In response to calls by FirstEnergy, American Electric Power and Exelon for subsidies to keep coal and nuclear plants operating, Duane co-authored a recent PJM study that counseled against such interventions. (See PJM Study Defends Markets, Warns State Policies can Harm Competition.)
“I do take issue with the idea that the entire nuclear fleet is at risk across the board. There’s always been well-run nukes … and the well-located ones are doing well,” he said, calling the predicted demise “hyperbole.”
Duane said markets have responded to environmental regulations in unexpected ways. EPA’s Mercury and Air Toxics Standards rule “is kind of a national experiment in that it’s imposing costs on every coal plant, whether it’s in an organized market or a regulated market,” Duane said.
“I thought I was going to write [that] the unregulated markets were ruthlessly efficient and regulated markets [were] holding onto that invested capital longer. We cut it every which way: the age of the resource; the size of the resource; the heat rate efficiency. And every time, we came up with no statistical difference … as both are doing a comparable job of pushing out the inefficient coal resources.”
Even where gas supplies are distant, market signals still point toward that fuel source.
“We are having more gas units come in through our capacity auctions, but we haven’t really had any gas infrastructure built,” said Kevin Flynn, senior regulatory counsel at ISO-NE.
Natural gas provides about half the energy in New England now, up from about 15% in 2000.
And as policymakers mandate more renewable energy resources, their integration requires more quick-start resources, usually natural gas, to maintain system balance, he added.
Because inadequate gas supplies exist during winter cold snaps, ISO-NE added its Pay-for-Performance program to incentivize generators when they’re needed most. It starts in 2018.
More than 3,000 MW of gas-fired generation has cleared in the last two Forward Capacity Auctions. “What we found in FCA 10 is that all gas resources that cleared are dual-fuel, as that’s the way the market is responding to Pay-for-Performance,” Flynn said. (See FERC Accepts ISO-NE Auction Results.)
The region has lost most of its coal fleet, and much of its nuclear generation is at risk. Vermont Yankee closed at the end of 2014, and Pilgrim in Massachusetts will leave the market in 2019.
Two nuclear units in New York are at risk, as the James A. FitzPatrick plant is set to close in the spring, and the R.E. Ginna plant could follow at the end of its reliability support services agreement, also early next year.
From 2010 to 2016, 11,665 MW of generation was built to replace aging or retiring units, representing about a quarter of the state’s total capacity of 39,000 MW, NYISO Assistant General Counsel Carl Patka said.
“We’re seeing a greater amount of deactivation notices, especially in western New York. Not a great surprise to see some of the older coal units” retiring, he said.
The retirements will make it a challenge for NYISO, which has a reserve margin of 20%, to maintain its reliability.
DETROIT — MISO’s Independent Market Monitor added eight new recommendations in its 2015 State of the Market Report.
The 124-page report concluded that MISO’s energy and ancillary markets “generally performed competitively” last year.
Monitor David Patton outlined the recommendations, four of which involve resource adequacy and planning, before the Markets Committee of the Board of Directors on Wednesday:
Energy Pricing and Transmission Congestion
Disable price setting by offline resources in extended locational marginal pricing (ELMP) and expand the share of online generators eligible to set prices to include those with start times of one hour or less and minimum run times of two hours or less, regardless of whether they are scheduled in the day-ahead market.
MISO has proposed increasing the share of online peaking resources able to set prices to 14% from the current 2% in ELMP Phase II, which would eliminate $4.4 million in revenue sufficiency guarantee (RSG) payments. Patton said the RTO should permit pricing by 90% of online peaking resources, which he said would eliminate $20 million in RSG payments.
The Monitor said offline resources should only set prices when they are economic and can be started quickly to address a shortage — a threshold it said was met by less than 10% of the offline resources that currently set prices. “Accordingly, we conclude that ELMP’s offline pricing is inefficiently changing prices during shortage conditions and recommend that MISO disable the offline pricing logic as quickly as possible,” the report says.
Board member Paul Feldman said the negligible benefits of ELMP were “disappointing.” (See “‘Modest’ Price Impacts as Extended LMP Enters Phase 2,” MISO Market Subcommittee Briefs.)
Jeff Bladen, executive director of MISO market services, said ELMP Phase I was “designed to be conservative” and that MISO is analyzing the Monitor’s recommendation.
Increase use of temperature-adjusted and short-term emergency ratings for transmission facilities.
Guarantee Payment Eligibility Rules and Cost Allocation
Begin modeling the voltage and local reliability requirement in the day-ahead market.
Improve Dispatch Efficiency and Real-Time Market Operations
Address “poor” dispatch performance and state estimator model errors in real-time operations by improving tools and procedures.
Resource Adequacy and Planning
Implement firm capacity delivery procedures with PJM instead of using pseudo-tied resources.
The Monitor said a firm capacity approach with PJM “would guarantee the delivery of the energy from MISO capacity resources to PJM, while maintaining the efficiency and reliability of MISO’s dispatch.”
In its quarterly report for spring 2016, Patton said 100 new market-to-market flowgates were created between March and June when MISO pseudo-tied 22 resources to PJM territory. Congestion on the new constraints totaled $22 million for the quarter, a six-fold increase over the first quarter.
Patton said the M2M process doesn’t have an efficient enough response for pseudo-ties positioned farther from the seam.
The next batch of pseudo-tied resources to be committed outside of MISO will occur in June 2017.
“We expect higher congestion as this process unfolds. We hope PJM gets tired of these high prices … and bearing the cost of MISO congestion. It’s certainly bad for the Eastern Interconnect,” Patton said.
However, PJM has said it will not consider firm capacity delivery as an alternative to continue pseudo-ties, he said.
MISO CEO John Bear said the RTO is discussing the issue with PJM but doesn’t expect a resolution until the middle of 2017.
“I’d encourage both parties to go back to the beginning,” board member Michael Curran said. “Untying this knot could be more difficult than going back to the beginning and saying, ‘how did we get here?’”
Improve the modeling of transmission constraints in the Planning Resource Auction.
Improve the physical withholding mitigation measures for the PRA by addressing uneconomic retirements and recognizing affiliates.
The report says falling capacity margins will leave MISO more vulnerable to physical withholding and cites Tariff provisions that it says prevent the RTO from addressing it. “First, the physical withholding thresholds are applied on a market participant basis, rather than a company basis. This would allow a large supplier to create multiple market participants to effectively circumvent the mitigation. Second, it is not clear [that] retiring a unit that is clearly economic to continue operating would be considered physical withholding and subject to MISO’s mitigation measures.”
Improve modeling of the limit on transfers between MISO South and Midwest regions in the PRA.
MISO’s recent settlement with SPP and other parties allows the RTO to transfer as much as 2,500 MW from MISO South to Midwest. But in the most recent PRA, MISO set a limit of only 874 MW.
The Monitor said the transfer limit in the PRA should equal the total transfer limit minus a derating factor that represents the probability that MISO neighbors will request a derating because of an emergency. “This recommendation would have had a substantial effect on the clearing prices in most of the Midwest zones in the most recent PRA for planning year 2016/17,” it said.
Incentives for New Investment Lacking
Curran said the board would schedule a conference call with MISO and the Monitor for a more in-depth conversation on the remaining recommendations.
Patton said long-run price signals continue to discourage new investment, with net revenues declining in 2015. The Monitor noted the $27/MWh average electricity price was 32% lower than in 2014. Natural gas prices fell 50% for the year to their lowest levels since MISO launched its energy markets in 2005.
Milder weather in 2015 caused average load levels to fall 2% from 2014. The peak load of 120 GW, set in July, was well below the forecast peak of 127.3 GW.
Gas-fired generation increased its share of total output from 17% to 23% over the year. Gas-fired resources were central to price-setting, “setting the system marginal price in 76% of intervals and locational prices somewhere in MISO in 95% of intervals,” the report said.
Patton said the spring 2016 quarter was competitive, attributable in part to continued low natural gas prices. The average cost of energy was $21.50/MWh, about 20% lower than in spring 2015.
Board member Thomas Rainwater asked how much MISO’s market would have to value carbon to incentivize continued operation of nuclear units. Patton said if carbon was valued at $20/short ton, nuclear resources would be closer to recovering costs. Patton also said expansion of wind generation is not the most cost-effective means to reduce carbon but is currently economic because of subsidies.
Board members expressed concern that the Monitor’s report included capacity margin values for the summer that differed from the RTO’s projected 18.2% summer reserve margin.
The Monitor’s base case scenario predicted a 20.5% margin because Patton said the 1,000-MW North-South transfer limit is too “pessimistic.” For its margin, MISO assumes 1,203 MW of capacity in MISO South cannot be accessed because of the North-South transfer limit. However, in the Monitor’s one-year-in-10 scenario, in a high-temperature, high-load forecast, the reserve margin falls to 11.6%.
Board members questioned the disparate reserve margins and asked why the board wasn’t presented with them during MISO’s summer readiness presentation. (See “MISO Prepped for Summer Demand,” MISO Markets Committee of the Board of Directors Briefs.)
“If MISO doesn’t see the world in the same way, our numbers may not match,” Patton said, reminding the board that the Monitor is independent of MISO.
Board members asked that Patton display his results alongside MISO’s in future summer readiness presentations. MISO and the Monitor agreed.
MISO’s Shawn McFarlane also delivered the RTO’s quarterly report during the meeting:
Average load for the spring was 86.3 GW, 2.7% lower than last spring.
Natural gas prices averaged $1.87/MMBtu, a 34.2% decline relative to spring 2015.
Total forced and planned generation outages accounted for 23.8% of market capacity: Planned outages averaged 23.6 GW, an 18% drop from spring 2015; forced outages averaged 19.3 GW, up 5.5%.
Average wind generation increased to 5.6 GW, 4.5% higher than last spring. Wind production was 4,934 GWh in April, setting a new monthly record.
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.
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.
