Page 1725 – RTO Insider

September 17, 2015

NOPR Requires RTOs Switch to 5-Minute Settlements

By Rich Heidorn Jr.

FERC issued a preliminary order Thursday that would require RTOs and ISOs to align their settlement and dispatch intervals, saying it was the first of a number of proposals the commission plans to act on based on what it learned from the price formation proceeding it began last year.

The Notice of Proposed Rulemaking (RM15-24) would require organized markets to settle real-time energy and operating reserve transactions financially at the same five-minute time interval that it dispatches those resources. It would also require the markets to eliminate any lag between declaring a shortage and beginning shortage pricing.

Inaccurate Price Signals

The commission said current practices in some markets are not resulting in appropriate price signals.

Although all organized markets dispatch resources in five-minute intervals, ISO-NE, MISO and PJM settle those transactions based on the average price for all dispatch intervals during the hour (“hourly integrated prices”).

“This misalignment between dispatch and settlement intervals may distort the price signals sent to resources and fail to reflect the actual value of resources responding to operating needs because compensation will be based on average output and average prices across an hour rather than output and prices during the periods of greatest need within a particular hour,” the commission said.

In addition, some markets do not trigger shortage pricing unless the shortage lasts a minimum time — resulting in a delay before prices begin reflecting the shortage. The rule would require a shortage of any duration to be reflected in prices.

FERC said the changes “will help provide correct incentives for market participants to follow commitment and dispatch instructions, to make efficient investments in facilities and equipment, and to maintain reliability. The proposed reforms will also help provide transparency and certainty so that market participants understand how prices reflect the actual marginal cost of serving load and the operational constraints of reliably operating the system.”

“Requiring settlement intervals to match dispatch intervals would make resource compensation more transparent by, among other things, increasing the proportion of resource payment provided through payments of energy and operating reserves rather than uplift,” the commission continued. “This increased transparency, in turn, better informs decisions to build or maintain resources and enhances consumers’ ability to hedge.”

Comments on the proposed rule will be due 60 days after its publication in the Federal Register.

Offer Cap Issue Coming to FERC

FERC’s price formation proceeding included workshops and staff reports touching on a variety of obscure — but often controversial — issues, including offer caps and uplift allocation. (See FERC Sets Feb. 19 Deadline on Price Formation Comments.

In its Thursday order, FERC said it “expects to undertake further action addressing various price formation topics, including offer price caps, mitigation, uplift transparency and uplift drivers,” though it gave no schedule for future action.

But the commission will be facing the offer cap issue shortly, with PJM planning to seek a rule change — with or without stakeholder consensus — by the end of October. The Markets and Reliability Committee will discuss the issue in a special meeting Thursday. (See PJM Stakeholders Weigh 4 Options on Offer Cap; No Agreement in Sight.)

MISO also plans a filing on the cap before winter. (See related story, MISO Focused on Gas-Electric Coordination, Fuel Assurance for Winter.)

Commissioner Tony Clark had indicated his desire for a gradualist approach last month. (See FERC’s Clark: Energy Markets Need Tweaks, not Overhaul.)

But Commissioner Philip Moeller was impatient. “I wish we had done a little bit more and a little bit sooner,” he said Thursday. Moeller’s term expired June 30, but he has remained on the panel awaiting a new nominee from President Obama.

Industry, RTO Reactions

The Edison Electric Institute praised the commission’s action.

“We thought [the NOPR] was a good start to a really comprehensive look at these issues,” said Richard McMahon, EEI’s vice president of energy supply and finance. “The fact that they teed up these other important issues [for future action] is very encouraging.”

The current disconnect means resources will be under-compensated for energy produced during price spikes, or overpaid for energy produced during low prices in an hour where most intervals have high prices.

MISO

MISO’s Market Monitor David Patton has been recommending five-minute settlements since his 2012 State of the Markets Report.

“Even though a very small share (1 to 2%) of the energy produced and consumed in MISO is settled through the real-time market, the spot prices produced by the real-time market affect the outcomes and prices in all other markets,” Patton said in his 2014 report in June. “For example, prices in the day-ahead market, where most of the energy is settled, should reflect the expected prices in the real-time market. Similarly, longer-term forward prices will be determined by expectations of the level and volatility of prices in the real-time market. Therefore, one of the highest priorities from an economic efficiency standpoint must be to produce real-time prices that accurately reflect supply, demand, and network conditions.”

Patton said MISO has the metering and data necessary to make the change, which he said will require “only modest changes to MISO’s existing settlement calculations.”

At its Market Subcommittee meeting in August, MISO categorized the switch to five-minute settlements for generation schedules as “planned” and said that it was evaluating the “market efficiency benefits” and “process and system impacts.”

MISO implemented five-minute settlements for interchange schedules, as required by FERC Order 764, on June 30.

“We’re in the process of reviewing the NOPR now and will begin discussions with stakeholders soon about the implementation and timing,” MISO spokesman Andy Schonert said. The RTO addressed the implications of sub-hourly settlements in its comments to FERC on the price formation initiative in March. (See pp. 17-18 of the comments.)

PJM

In an April order on pricing of reserves, FERC rejected as out of scope a call from Public Service Enterprise Group that PJM implement five-minute settlements (ER15-643).

PJM Executive Vice President and COO Mike Kormos said in an interview after the FERC meeting that the change “was on the radar for sure.”

He noted that the order may require generators to make software changes and update old meters.

“It’s not just going to be ‘What’s the impact on PJM?’” he said. “It’s ‘What’s the impact on everybody?’”

ISO-NE

ISO-NE is already discussing with market participants a switch to five-minute settlements. At the Sept. 2 New England Power Pool Markets Committee meeting, RTO officials said they plan to settle generation, pump hydro and imports and exports on a five-minute basis but will continue to settle load assets and bilaterals hourly in real-time.

ISO-NE spokeswoman Marcia Blomberg said the idea of settling bilaterals subhourly also is under discussion.

Real-time reserve payments and inadvertent energy also would be settled every five minutes but the charge allocations would remain hourly.

On Sept. 2, the RTO told the NEPOOL Markets Committee that it plans to present Tariff language changes in November with a vote in December and implementation in 2017.

“We’re still reviewing the NOPR and evaluating what’s needed for compliance, but in terms of the proposal we’re discussing with participants, significant changes to the ISO’s settlement systems would be required to accommodate new calculations and significantly increased data volume, and market participants’ information systems would also require changes,” Blomberg said Monday.

September 16, 2015

NYISO Taps ERCOT Exec as New CEO

NYISO announced Wednesday that its Board of Directors has selected Bradley C. Jones, senior vice president and COO of ERCOT, to replace Stephen G. Whitley as president and CEO, effective Oct. 12.

Jones is a distinguished energy industry executive with 29 years of wide-ranging experience, including grid operations, power plant operations, generation development, project finance, wholesale and retail market design, and regulatory and legislative affairs.

At ERCOT, Jones had responsibility for operations, grid planning and commercial operations.

Jones (left), Whitley (right) (Source: NYISO)

Jones joined ERCOT from Luminant, the competitive generation subsidiary of Energy Future Holdings, where he was vice president for government affairs. He previously worked at TXU Corp., rising from a plant engineer to become vice president for generation development.

A licensed professional engineer, Jones has a bachelor’s in mechanical engineering from Texas Tech University at Lubbock and an MBA from the University of Texas at Arlington.

“Brad has a strong commitment to reliability and a firm belief in the power of markets to benefit consumers,” NYISO Chairman Michael Bemis said in a statement. “His talent, experience and demonstrated commitment to excellence make him a great choice.”

Jones was chosen following a nationwide search conducted by Heidrick & Struggles. He could not be immediately reached for comment.

Whitley, appointed CEO in 2008, will remain with the ISO during the transition and then act as an advisor to the board.

Rich Heidorn Jr.

September 15, 2015

FERC ALJ Rejects $10 Million in PATH Transmission Project Recovery

By Rich Heidorn Jr.

The developers of the abandoned PATH transmission project would be denied recovery of more than $10 million of their $121.5 million claim under an initial decision by a FERC administrative law judge Monday.

Judge Philip C. Baten recommended that the commission deny the developers, American Electric Power and the former Allegheny Energy (now FirstEnergy), recovery of lobbying and advertising costs as well as part of their legal costs and losses on the sale of the property they acquired (ER09-1256-002, ER12-2708-003). The commission can accept the recommendations in whole or in part.

The proposed 765-kV “coal by wire” Potomac-Appalachian Transmission Highline project was approved by PJM in 2007 to run from AEP’s John Amos coal generator in St. Albans, W.Va., to New Market in Frederick County, Md.

By 2011, however, PJM said the need for the line had moved several years beyond 2015 due to reduced load growth following the recession. The PJM Board of Managers ordered transmission owners to suspend work on the line pending a more complete analysis in 2011 of all upgrades in its regional transmission plan and terminated it in 2012.

Victory for Pro Se Interveners

Although the developers would recover most of their request, the judge’s ruling was a victory for two PATH opponents from West Virginia, Keryn Newman and Allison Haverty, who filed a pro se intervention challenging the companies’ request for recovery of $6 million in spending on lobbying and advertising campaigns intended to win political support for the project. The judge denied recovery of any of the expenses.

Baten also said $3.6 million in losses that the companies incurred on past land sales are not recoverable and that recoveries from any future land transactions “must be accomplished by commercially reasonable procedures.”

The judge also denied recovery for part of $3.9 million in legal expenses, for which the companies’ failed to provide documentation, and cut the companies’ proposed 10.4 % return on equity for the abandonment costs to 6.27%.

But Baten approved recovery for the purchase of property for a planned substation in Maryland and rejected a request by state consumer advocates to reject $29 million in spending incurred in 2010-2012 as imprudent.

The advocates said that the PATH companies should have recommended to PJM that the project be terminated by the beginning of 2010 and that expenses between that point and the actual termination should be denied.

The judge ruled that the expenses were recoverable because the PATH companies had a contractual obligation to construct the transmission projects as assigned by PJM. “The PATH companies did behave as a prudent utility by proceeding with their assigned obligations until otherwise instructed by PJM,” he wrote.

First Impression

Baten said that the case “presents significant issues of first impression” on FERC Order 679, a 2006 initiative that sought to accelerate transmission investment through incentives.

“This case addresses some new issues and gives the commission a unique one-stop opportunity to review and set policies for the comprehensive litigation scheme arising from Order No. 679,” Baten wrote.

The PATH project was initiated with PJM’s 2007 Regional Transmission Expansion Plan, and in 2008 FERC accepted a formula rate that entitled the developers to recover all prudently incurred costs if the project were cancelled.

In 2012, the companies filed for recovery of $121.5 million in abandonment costs. After settlement attempts with opponents failed, hearings in the case were held in March and April.

Lobbying Campaign

The pro se interveners contested spending on public relations agencies, advertising and public coalitions intended to influence public officials during the zoning and certificate of public convenience and necessity (CPCN) proceedings in Maryland, Virginia and West Virginia.

“When utilities are seeking selection or CPCN approvals from governmental entities, the utilities should rely on the established governmental approval processes to persuade the officials and not indulge in collateral efforts such as public education, outreach and advertising activities,” the judge ruled. “… If the selection or CPCN application has merit, the governmental selection process provides a sufficient vehicle for the utilities to present their engineering, marketing and economic studies and thereby hope to merit the vote of approval from these officials. In this regard the PATH companies spent over $8 million on attorney fees to prosecute the CPCNs before the respective governmental bodies, which begs the need for these collateral expenses.”

Among the spending rejected was $332,000 on a public opinion poll, $2.7 million in advertising and $94,000 paid to the then head of the West Virginia Democratic Party, Larry Puccio.

The judge said that the “nature and origins of the PATH companies’ business relationship with Puccio are somewhat amorphous” and that the companies paid him $31,000 “before his assignments were even formulated.”

“The invoices of record provide little description of his services. When the PATH companies were asked in discovery to provide additional details, their response was that such records are not available. While the PATH companies make protestations that Puccio’s services were not to lobby and instead were to educate the public and public officials, without proper documentation the only factual inference that can be drawn is that his services were to influence public officials, and the PATH companies have failed in their burden of proof to show otherwise.”

September 15, 2015

Federal Briefs

A federal appeals court panel rejected the first effort of a collection of states to block the Obama administration’s power plant climate rule, deciding the states can’t ask for the plan to be killed before legal challenges are complete.

The D.C. Circuit Court of Appeals issued a two-paragraph order Wednesday evening, ruling that more than a dozen states and a coal company cannot be granted a stay of the Environmental Protection Agency’s Clean Power Plan, which aims to cut carbon emissions by 32% in 15 years.

The panel ruled that legal challenges can only be mounted after the final rule is published in the Federal Register, which is expected in October.

More: The Hill

AP Study Finds Waste Spills Follow Oil and Gas Drilling Booms

An Associated Press analysis shows that more than 175 million gallons of wastewater were spilled in more than 21,000 individual incidents at oil and natural gas drilling sites between 2009 and 2014. The report says that even more incidents go unreported.

The wastewater spills can be even more damaging to the environment and agriculture than oil spills. AP reported that in seven of 11 states examined, the amount of wastewater released was at least twice as much as the amount of oil spilled. It said that spilled oil can be absorbed and broken down by microbes, but briny wastewater can be deadly and long lasting to crops, trees and livestock.

“Oil spills may look bad, but we know how to clean them up and … return the land to a productive state,” said Kerry Sublette, a University of Tulsa environmental engineer. “Brine spills are much more difficult.”

More: Associated Press

API and ANGA Eying Merger, Sources Say

The American Petroleum Institute and America’s Natural Gas Alliance, two of the country’s largest oil and gas industry groups, are considering a merger, according to Politico.

The news site says the move may be spurred by the low prices of oil and natural gas, and the feeling by some of the groups’ members that membership in both organizations is costing too much. The story also noted that the positions and strategies of both groups are growing ever closer, especially in the areas of oil exportation and natural gas production in shale-field regions.

API Chief Jack Gerard is one of the lobbying industry’s highest paid members. Federal disclosure forms show he received $13.3 million in compensation in 2013.

More: Politico

NRC Ends Study of Cancer Risks Near Nuclear Plants

The Nuclear Regulatory Commission, citing budget constraints, is ending a National Academy of Sciences study of cancer risks near nuclear generating stations.

“We’re balancing the desire to provide updated answers on cancer risk with our responsibility to use congressionally provided funds as wisely as possible,” said Brian Sheron, director of the NRC’s research office. “The NAS estimates it would be at least the end of the decade before they would possibly have answers for us, and the costs of completing the study were prohibitively high.”

The study was started in 2010, and the first phase was completed in 2012. It consisted of recommendations for the second stage of the study, which was estimated to cost $8 million and could take an additional 10 years.

More: The Hill

Poll Finds 73% of Americans Favor Greater Limits on Ozone

A poll commissioned by the American Lung Association has found that 73% of Americans want the Environmental Protection Agency to set stricter limits on ozone pollution. The EPA proposed stricter limits in November that would restrict ozone levels in the air to between 65 parts per billion (ppb) and 70 ppb. The current limit is 75 ppb.

“Millions of Americans are breathing polluted air and suffering from asthma attacks, increased risk of respiratory infections, and even premature death,” said Harold Wimmer, ALA’s national president.

Manufacturing groups oppose changing the limits. “While western states have cut their production of smog-causing ozone by over 20%, studies show that pollution from China has offset much of that progress,” an advertising campaign by the National Association of Manufacturers says. “These rules won’t hurt China, but they could cost our country more than $1 trillion.”

More: The Hill

FERC Names Carmen Cintron Administrative Law Judge

FERC has named Judge Carmen Cintron as deputy chief administrative law judge. She will assist FERC Chief Administrative Law Judge Curtis Wagner Jr. with the Office of Administrative Law Judges and Dispute Resolution.

Cintron has been with FERC since 1999. She was a hearing-office chief of the Social Security Administration’s Atlanta North Office of Hearings and Appeals, overseeing an office of 11 administrative law judges and a staff of 50. She previously worked as an administrative law judge in the administration’s San Jose, Calif., office. She worked 14 years with the Federal Communications Commission as an attorney before that.

More: FERC

Feds Eyeing Future Open Ocean Leases off SC

Officials with the federal Bureau of Ocean and Energy Management have identified two areas offshore of South Carolina as possible sites for wind power facilities.

The next step would be an environmental assessment of the sites. One is off Myrtle Beach; the other is off Cape Romain, toward the state’s southernmost area.

Federal officials spoke to members of the South Carolina Renewable Energy Task Force, saying it would probably be seven years before an operating wind farm is anchored off South Carolina’s coast.

More: Penn Energy

September 15, 2015

Company Briefs

SunEdison will pay $300 million for 33% of Dominion Resources’ solar assets, which are rated at 425 MW.

The deal, announced last week, gives SunEdison the option of acquiring the rest of Dominion’s solar portfolio, which includes 24 projects in California, Connecticut, Georgia, Indiana, Tennessee and Utah. Fifteen of the facilities went into service in 2013 or 2014. The rest are scheduled to go into service this year. All have long-term power purchase agreements in place. The agreement needs the approval of FERC.

Dominion CEO Thomas Farrell II said the company is not getting out of the solar business, but is “shifting from constructing contracted solar to constructing utility solar in Virginia, where we expect 400 MW of generating capacity by 2020.”

More: MarketWatch; NASDAQ

Energy Storage Market Showing Signs of Record Quarters

The price for energy storage is coming down, with the median price for utility-scale battery systems in the $900/kWh range in the first and second quarters.

GTM Research reported that the low price declined from $800/kWh in the first quarter to $750/kWh in the second. The decline was partly attributed to improvements in energy-storage technology, as well as competitive pressure from Tesla, which announced it aimed to turn out batteries for about $250/kWh.

Meanwhile, battery deployment continues to rise, with 40.7 MW of capacity installed in the second quarter, six times the amount reported in the previous quarter and nine times more than the previous year.

More: GTM Research

Solar Capacity Hits Record of Almost 1,400 MW Installed

The second quarter of 2015 saw solar power capacity installation of 1,393 MW, pushing the market total to about 20 GW. Most of the new capacity was from utility installations.

Residential solar, too, set a record, with 473 MW being installed in the same quarter, a 70% increase over the same period the year before, according to the Solar Energy Industries Association quarterly market report.

SEIA President Rhone Resch urged government to maintain the momentum by renewing the investment tax credit set to expire next year. “The demand for solar energy is now higher than ever and this report spells out how crucial it is for America to maintain smart, effective, forward-looking public policies, like the ITC, beyond 2016,” he said.

More: The Hill

Duke Energy Adds 30 MW of Solar to Fleet, 132 MW more Coming

Duke Energy Renewables reported that it has completed construction of four solar farms in North Carolina, adding 30 MW of capacity to its solar stable. All four facilities are in Eastern North Carolina, and all are under contract to provide their output to Dominion NC Power.

Duke said it has three more facilities — totaling 132 MW — under construction, including one that will produce 80 MW, which it billed as the largest solar project east of the Mississippi.

Duke Energy Renewables already has 105 MW of solar generation in North Carolina.

More: Charlotte Observer

GE Gets European Regulators’ OK for Alstom Acquisition

European regulators approved General Electric’s $13.5 billion acquisition of the power generation portion of French company Alstom. Regulators said GE had addressed all antitrust concerns. GE wants to use Alstom’s power generation and power grid equipment business to boost its presence in those industries.

GE CEO Jeffrey R. Immelt said the acquisition would bring the company back into the industrial equipment business and away from its previous foray into financing, which is seen as riskier. As a condition of the regulatory approval, GE has agreed to divest some of the Alstom power generation business to Italian company Ansaldo Energia.

More: The New York Times

Golden Spread’s ‘Beast,’ Gas CTs Supplies SPP, ERCOT Grids

Golden Spread Electric Cooperative last week unveiled the first of three 191-MW natural gas turbines it is constructing at its Antelope Elk Energy Center north of Lubbock, Texas. The site is strategically located at the intersection of two major power grids.

The project incorporates General Electric’s latest 7FA.05 combustion turbines, which can reach 70% capacity within 10 minutes, making them ideal to use in conjunction with the region’s intermittent wind and solar production. Golden Spread is also installing grid-switching equipment that will allow the units to supply power to either SPP or ERCOT, the two electric grids in which Golden Spread serves its 16 distribution cooperative members.

ERCOT CEO Trip Doggett and SPP president and CEO Nick Brown were among those attending the power plant’s debut. Brown applauded Golden Spread for having the vision to construct the Antelope Elk Energy Center at a crossroads between two major power grids, and to embrace a strategy to integrate quick-fire generation technology with renewable energy sources.

More: Plainview Herald

Ameren Targets Investments in Illinois over Missouri

After several failed attempts to change Missouri’s utility laws, St. Louis-based Ameren is shifting capital away from Missouri and into federally regulated transmission lines and its electric and natural gas holdings in neighboring Illinois. It says it plans to invest far less into its larger Missouri utility’s infrastructure over the next five years.

Ameren says Missouri’s regulations governing monopoly utilities make the state less attractive for investment. It said Illinois changed its electric utility laws in 2011 to give utilities more certainty during rate cases in the hopes of spurring more investment in electric infrastructure.

Illinois’ framework is similar to the ratemaking process at FERC, which governs transmission lines. Along with a more favorable ratemaking process for utilities, FERC lets them earn a higher return on investment than allowed by state regulators in order to encourage a build out of the electric grid.

More: St. Louis Post-Dispatch

Exelon Names Linda P. Jojo to New Seat on Board of Directors

Exelon notified the Securities and Exchange Commission that it increased the number of board seats to 14 and that it named airline executive Linda P. Jojo to the new seat effective Sept. 1.

Jojo is chief information officer and executive vice president of United Continental Holdings. She previously held similar positions with United Airlines, Rogers Communications and Energy Future Holdings.

Exelon said she will serve until the 2016 annual meeting. She will serve on the board’s finance and risk committee.

More: Bloomberg; SEC

Duke Energy Settles with Feds on 15-Year-Old Clean Air Violations

Duke Energy will pay a penalty of nearly a million dollars and invest $4.4 in environmental mitigation projects to settle charges that it violated clean-air laws 15 years ago by modifying coal-fired generating stations without emissions control equipment.

The proposed settlement was reached with the Environmental Protection Agency and the U.S. Department of Justice. The company has already shut down 11 of the 13 units at the North Carolina coal plants that were cited for violations. The shutdowns become permanent as part of the settlement. Duke must continue to operate emissions control systems and meet emissions limits at the two remaining units at its Allen power plant in Belmont. The settlement calls for the company to retire those units by the end of 2024.

“After many years, we’ve secured a strong resolution, one that will help reduce asthma attacks and other serious illnesses for the people of North Carolina,” said Cynthia Giles, assistant EPA administrator for enforcement.

More: Associated Press; EPA

Westar Wants to Build ‘Subscription-Based’ Solar

Westar is planning to build a community solar garden of up to 10 MW and is seeking help in getting it built.

The Kanas utility issued a request for proposals from qualified solar developers. It hasn’t decided yet whether it will be a ground-based or elevated solar facility. It wants the facility to be completed by the end of 2016.

Developers have to file a notice of intent with Westar by Sept. 25 and submit their final proposal by Oct. 19.

More: Topeka Capital-Journal

SolarCity Signs Hawaiian Utility for Solar, Energy Storage Project

A Hawaiian utility has signed a power purchase agreement with SolarCity to buy stored solar-generated power during the evening, when demand is higher. SolarCity said it is able to generate electricity during the day, store it, and release it during the night.

The 52-MW battery system is joined with a 13-MW solar facility. The Kauai Island Utility Cooperate said the arrangement will make it less reliant on diesel generation, saving money and reducing greenhouse gas emissions.

KIUC already operates two 12-MW solar farms.

More: Pacific Business News

New SPP Connections Lead Xcel Energy to Offer Refunds to Texas Customers

Xcel Energy is refunding $18.6 million to Texas retail customers in the Panhandle and South Plains, thanks to lower fuel and purchased-power costs that were made possible by new transmission line connections with SPP.

David Hudson, president of Xcel Energy’s Southwestern Public Service, said new transmission lines connecting Xcel with SPP have expanded the purchase of competitively priced power. Xcel’s ability to import from SPP increased from a little more than 400 MW two years ago to as much as 1,700 MW today. In addition, natural gas prices remained very low through the first part of this year.

Texas residential customers using 1,000 kWh/month will see a one-time credit of $34.42, prorated over two billing cycles.

More: Xcel Energy

Manitoba Hydro Names CFO Interim Chief Executive Officer

Darren Rainke, Manitoba Hydro’s chief financial officer, has been named interim chief executive officer of the public power company. He will take the place of Scott Thompson, who announced he was stepping down in June to take a position in the private sector.

Rainke will continue to be CFO while the company looks for a permanent chief executive.

More: CBC News

Pipeline Company Moves Ahead Without Regulatory Approval

Although it still needs regulatory approval from four states, Energy Transfer Partners is moving ahead with construction preparations for its Dakota Access Pipeline. The Texas company is stockpiling the pipe it will need for the $3.8 billion, 1,130-mile crude oil pipeline. The project is designed to move crude from North Dakota to a terminal in Illinois, from where it will be sent to markets in the East and Southeast.

But it is a gamble. The pipeline still needs approval from North Dakota, South Dakota, Iowa and Illinois. “What the company does is at their own risk,” said North Dakota Public Service Commission Chairwoman Julie Fedorchak.

Energy Transfer Partners has pipeline and other materials stockpiled at storage yards in North Dakota, South Dakota, Illinois and Iowa.

More: Quad City Times

September 15, 2015

ERCOT Expects Sufficient Generation for Fall, Winter

By Tom Kleckner

ERCOT’s seasonal assessments of resource adequacy (SARA) for the fall and winter predict enough generation available to serve forecasted peaks.

The Texas grid operator’s fall SARA shows 77,289 MW of generation available this October and November, more than enough to meet its expected peak of 49,709 MW.

According to the preliminary winter SARA, ERCOT will have 78,253 MW available to meet a projected peak demand of 57,400 MW from December through February 2016. A final winter assessment with an updated weather forecast is scheduled for release Nov. 3.

ERCOT said it expects reserves to range from about 3,600 MW — should peak demand be significantly higher than expected — to nearly 15,000 MW under expected conditions.

“We’ve captured a wide range of scenarios,” said ERCOT’s Pete Warnken, manager of resource adequacy, in response to RTO Insider. “Based on our most recent scenarios, we feel very comfortable with our forecasts.”

ERCOT said it will “continue to monitor the potential effect of Texas’ future drought conditions on generation capacity and ongoing changes to environmental regulations.”

850 MW Additional Capacity Online

ERCOT has added 850 MW of installed capacity since its preliminary fall assessment was published in May, thanks to a combined-cycle generator and three wind projects. Another 1,058 MW of wind projects have been delayed beyond Oct. 1, and will no longer contribute to the fall’s expected capacity.

ERCOT senior meteorologist Chris Coleman said he expects average fall weather despite unusual weather patterns associated with warm ocean temperatures.

Coleman said El Niño this year could be the strongest since 1997, leading to colder, wetter and cloudier winter weather. He said it could also lead to more wind power generated. ERCOT generates about 1,000 MW of wind power during the winter and exceeds 4,000 MW during the summer.

The peak forecast is based on normal weather conditions for 2002-2013 during peak maintenance periods.

ERCOT’s all-time winter peak of 57,265 MW, set in February 2011, was nearly matched in January 2014. The 2014 conditions are reflected in the extreme scenarios included in the winter assessment.

One megawatt powers about 500 homes in Texas during mild weather conditions and about 200 homes during summer.

September 15, 2015

PJM Stakeholders Weigh 4 Options on Offer Cap; No Agreement in Sight

By Suzanne Herel

VALLEY FORGE, Pa. — Members debated four potential changes to the $1,000/MWh energy offer cap last week at a specially called meeting of the Markets and Reliability Committee, failing to agree on any one — or even which should be the main and alternate proposals.

Further discussion was deferred until Sept. 24, giving stakeholders only a few weeks to reach consensus before the Board of Managers takes the matter into its own hands before winter.

The proposals were presented by Direct Energy, Old Dominion Electric Cooperative, the Independent Market Monitor and — for the first time — Calpine and the PJM Power Providers Group (P3).

Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during periods of extreme temperatures, such as the 2014 polar vortex.

Direct Energy had kicked off the latest effort to reach agreement in July with its plan to raise the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers. The number is 50% more than the highest offers reported by PJM last winter. PJM said that it would support the Direct Energy proposal. (See PJM Stakeholders Struggle for Consensus on Offer Cap.)

Joe Wadsworth of Vitol reiterated his concern about potential unintended consequences inherent in applying different rules to the day-ahead and real-time markets. “We could be artificially creating arbitrage opportunities,” he said, adding that such a scenario might invite increased scrutiny from FERC enforcement.

“We need to ensure the day-ahead and real-time market parameters are the same whenever we can,” he said.

Jim Jablonski, of the Public Power Association of New Jersey, said that whatever the proposed offer cap is, it’s critical it be able to be supported by data. “We can’t get to FERC and say, ‘Oh, we just doubled the old one.’”

Jablonski asked Direct Energy’s Jeff Whitehead if he could estimate exactly how much uplift a higher cap might eliminate. “I’d love for somebody to say, ‘This is how much,’” he said.

Whitehead responded, “The higher the offer cap, the less uplift we’ll have.”

Steve Lieberman of ODEC called his plan “the only proposal that was a joint effort of load and supply.”

It would allow cost-based offers of up to $1,800/MWh and allow them to set LMPs.

And, he said, “Old Dominion firmly believes in the need for a cap that is the same in both markets.”

The Monitor’s proposal would allow cost-based offers to exceed $1,000/MWh when a unit’s short-run marginal costs exceed that cap. Price-based offers would have to be less than or equal to such cost-based offers. Monitor Joe Bowring said the approach addresses the issue of market power when the overall market is tight.

The P3 proposal was the only one that had not previously been presented.

In making the presentation, David “Scarp” Scarpignato of Calpine said that because generators have a must-offer requirement to enter into the day-ahead market, it’s essential they be able to recover their costs.

“The uplift method is a bad idea,” he said. “It’s unhedgeable, and there’s extra risks added to load prices. If you don’t put them into LMP, you lose a very important market signal.”

In allowing offers to set LMPs, according to the proposal, higher prices incent generators to perform.

Like Lieberman, Scarp said the day-ahead cap must equal the real-time cap. Under his proposal, cost-based offers for both markets would be capped at cost plus 10%; market-based offers would be capped at the higher of $2,700/MW or the cost-based offer.

The proposal also sets penalty factors of $1,350/MW for synchronized or primary reserves, and $750/MW for excess synchronized or primary reserves.

September 15, 2015

PJM Transmission Expansion Advisory Committee Briefs

PJM has reduced the number of potential transmission fixes for the AP South/AEP-DOM constraints to six candidates.

Six other projects were eliminated following sensitivity analyses for changes in load forecasts and fuel prices.

The projects remaining cleared the 1.25 benefit-cost ratio under all sensitivities and also reduced both AP South and AEP-DOM congestion in combined 2019 and 2022 simulations.

The six proposals include three by Dominion Resources and one submitted by Dominion High Voltage Holdings and Transource Energy (itself a partnership of American Electric Power and Great Plains Energy). The finalists also include one project each from LS Power and Duke-American Transmission Co. Costs of the projects range from $25 million to $301 million.

The fuel price sensitivity looked at natural gas costs $1/MMBtu higher and lower than the prices assumed in the base case. The load forecast sensitivity included an increase and decrease of 2% in load.

LS Power’s Sharon Segner questioned the planners’ screening. “There’s nothing that puts any kind of weight on the cost side and cost containment,” she said. LS Power’s $48.6 million proposal includes a cost cap.

Paul McGlynn, PJM general manager of system planning, said planners will consider cost certainty in further pruning the list of finalists.

Planners hope to select a winning project in time to include it in the 2015 Regional Transmission Expansion Plan.

Last month, they announced the selection of 11 other market efficiency projects with a combined cost of $59.2 million to address congestion in other areas of the footprint. (See “11 Market Efficiency Projects Selected; 12 still in running for AP South/AEP-DOM,” in PJM TEAC Briefs.) Those projects will be recommended to the PJM Board of Managers in October.

McGlynn noted that the RTO has done relatively few market efficiency projects in the past. “We’re very pleased to be having on the order of a dozen [market efficiency] projects to be taking to the board,” he said.

Planners also will reevaluate nine proposed projects to address constraints on the Loretto-Wilton Center 345-kV line, which caused the COMED locational deliverability area to bind in the 2018/19 Base Residual Auction in August. COMED cleared at $215/MW-day, $50 above the RTO price. (See PJM Capacity Prices Up 37% to $165/MW-day.)

The projects, with costs ranging from $11.5 million to $290 million, fell short of the 1.25 benefit-cost ratio in the original analysis. But one or more could clear the threshold if the analysis shows they can increase COMED’s capacity emergency transfer limit, McGlynn said.

Reliability Projects

The 2015 RTEP also will include reliability projects selected from among 91 proposals — 26 transmission owner upgrades and 64 greenfield projects — made in response to Window 1, which closed July 20. The window covered N-1 and N-1-1 thermal and voltage problems as well as generation deliverability and common mode outage and load deliverability issues.

The proposals range in cost from $13,000 to $167.1 million.

The RTEP recommendations also will include dozens of generation-related network upgrades (see pp. 34-68 of the PJM presentation).

Meanwhile, planners have begun reviewing proposals received in response to Window 2, which closed Sept. 4. The window sought solutions for transmission owner criteria and light load reliability criteria violations.

High Voltage Problem in AEP

Planners are considering more than $51 million in transmission upgrades to address a large increase in the number of high-voltage warnings in the AEP transmission zone and northeastern Mid-Atlantic regions. AEP also has seen a large increase in reactor switching for both low- and high-voltage conditions.

The problems, which generally occur during light load periods, are resulting from changes in dispatch due to new and deactivated generation, reactive support deficiencies and increased line charging from new transmission facilities.

Planners are considering spending $51 million to install a 450-MVAR static VAR compensator at the Jacksons Ferry 765-kV substation and a 300-MVAR shunt line reactor on the Broadford end of the Broadford–Jacksons Ferry 765-kV line in southern AEP.

They’re also planning six new shunt reactor installations in New Jersey, the cost of which is still being finalized.

Pratts Area Update

Planners said they will recommend selection of a Dominion project that requires no new right of way to address reliability problems near Pratts, Va.

pjm — PJM staff selected Dominion to build a 230-kV line from the Remington substation to the Gordonsville substation.

Dominion will build a new 230-kV line from the Remington substation to the Gordonsville substation and install a third 230/115-kV transformer at Gordonsville at an estimated cost of $103.7 million.

PJM announced last month it was reconsidering its selection of the Gordonsville-Pratts-Remington transmission upgrade after learning that it will require about 18 miles of new rights of way, far more than initially believed. The proposal from Dominion Resources and FirstEnergy was estimated at $129 million to $164 million.

The Virginia State Corporation Commission, which would have to approve the project, says that existing rights of way should be given priority as the locations for transmission additions.

In response to a question, McGlynn said planners had not independently verified Dominion’s assertion that the new line could be built in the existing 115-kV corridor. “We relied on the work of the entities that proposed the project,” he said.

A representative from Madison County, Va., which had urged PJM to reject the original plan, praised the new solution, saying it was “symmetrical with the identified need and an appropriate fix.” The county had complained that the original project was unnecessarily large for the rural county.

— Rich Heidorn Jr.

September 15, 2015

FERC Again Denies Polar Vortex Make-Whole Payments

By Michael Brooks

The cold weather temperatures produced by the polar vortex of January 2014 continue to haunt FERC.

The commission has denied another generator’s request for $1.3 million in make-whole payments for natural gas it purchased that was never used during the event, citing rules against retroactive ratemaking (ER15-952).

New Jersey Energy Associates, which owns the 290-MW South River combined-cycle plant, said PJM asked that a planned outage for the plant be canceled so it could be available for dispatch on Jan. 27, 2014. The plant purchased $2.7 million worth of gas, having been assured by PJM that it would be compensated for its fuel costs, according to NJEA. The RTO, however, repeatedly canceled the plant’s scheduled start time, forcing it to sell the gas at a $1.3 million loss.

The claims are similar to those of Duke Energy and Old Dominion Electric Cooperative. During the same week as NJEA’s claim, Duke purchased gas for $12.5 million when PJM said that its Lee plant in Illinois would be needed. The plant was never called on, however, and Duke was forced to sell the gas at a loss of $9.8 million. ODEC complained that PJM canceled multiple dispatches that left gas it had purchased unused and that it was due $15 million. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)

FERC, however, remained steadfast on its assertion that these kinds of complaints constitute retroactive ratemaking.

“Ratepayers had not received any prior notice of NJEA’s requested relief, which was sought roughly 12 months after the events in question,” the commission said. “We therefore conclude, as we did in the similar Duke and ODEC cases, that the relief sought by NJEA is prohibited by the filed rate doctrine and rule against retroactive ratemaking.”

FERC, however, did find that NJEA was entitled to recover its start-up costs under PJM’s Tariff. The Tariff allows market participants to recover costs related to the start-up of resources offered in the day-ahead energy market if PJM cancels its selection of those resources. While NJEA did not specify how much they would be allowed to recover under this provision in its complaint, it said “this would only be a fraction of its actual unrecovered costs.”

As he did in the Duke and ODEC cases, Commissioner Philip Moeller dissented. He once again noted that PJM is the only grid operator that does not allow its participants to vary their day-ahead energy market offers by hour or update their offers in real time.

As a result of the Duke and ODEC complaints, FERC found that PJM’s Tariff was potentially unjust and unreasonable in this regard and ordered the RTO to make Tariff changes by Nov. 1. While PJM agreed that changes were needed, and it began the stakeholder process to do so, the RTO told the commission in July that it would need until Nov. 1, 2016, to resolve the numerous questions raised by the changes (EL15-73).

“In light of this delay in reforming PJM’s markets,” Moeller argued, “the majority’s repeated failure to guarantee cost recovery for generators acting in good faith to ensure system reliability may regrettably impact reliability during the approaching winter of 2015-2016.”

September 15, 2015

Baker: New England Must Sacrifice to Lower Costs

By William Opalka

BOSTON — New England’s states may have to set aside their self-interests to overcome high energy prices that are slowing the region’s economy, Massachusetts Gov. Charlie Baker told the 2015 ISO-NE Regional Plan meeting on Thursday.

The first-term Republican said the region’s competitive advantages are at risk, citing a “sense of desperation” among his fellow governors over energy costs.

“One of the things that’s going to be most fundamental to our ability to succeed is to develop strategies and plans that can get a lot of people who don’t necessarily agree on things to come together and find a way to put the optimal success of the region above what might be the most optimal solution for any particular player,” he said.

“We don’t believe we can achieve the energy security, competitiveness, reliability and affordability … alone. It’s got to be a regional conversation,” he said.

Massachusetts, Rhode Island and Connecticut agreed earlier this year to seek multi-state, long-term contracts to procure large-scale renewable resources. More problematic is building large, multi-state electric transmission and natural gas pipeline projects.

“I think it’s pretty hard to look at the data and conclude that we won’t need to increase our capacity over time,” Baker said, referring to New England’s increasing reliance on natural gas generation and the fuel shortages that occur in the winter months. (See Dueling Studies Dispute Need for More Pipelines in New England.)

He also endorsed exploring the feasibility of importing more hydropower, which would require expensive power lines. “Canadian hydro has potential to be a significant player in the region,” he said, adding that the decision to proceed will depend on how the projects affect ratepayers. “If it doesn’t make sense, we won’t do it,” he said.

Policy Mandates Sometimes at Odds with Market Forces, Panelists Say

Following the governor’s address, a panel discussed whether the region’s pursuit of public policy initiatives is incompatible with low-cost energy.

Over the past 16 years, panelists said, New England’s energy strategy has often been at cross-purposes. The development of competitive markets, the transition from coal to natural gas generation, the integration of renewables and the need for expensive infrastructure all have made it difficult to keep rates affordable.

“In New England, our representatives have decided that renewable energy is really important, notwithstanding whatever preferences the market may have in its short-term, day-to-day interest,” said Edward Krapels, founder of Anbaric Transmission.

“I see us going down two paths,” he said. “The planning by the ISO to maintain reliability leads you down one path. Actions by the governors to create a clean energy economy take you down a parallel path and the two don’t converge.”

He said the three-state model for procuring renewables is the beginning of that convergence.

Public policy has had to contend with “the historical forces of technology and geology” — cheap natural gas — said Katie Dykes, deputy commissioner for energy at the Connecticut Department of Energy and Environmental Protection.

“This low gas price environment that we’ve had has done more for the fuel mix of this industry than the [Environmental Protection Agency] and the environmental advocates have been able to do over the last several years,” said Bob Hayes, vice president of natural gas trading for Calpine.

But he cautioned that the region’s dependence on liquefied natural gas “for the foreseeable future is a precarious one at best and one that I’d definitely be concerned about.”

Tanya Bodell, executive director of research firm Energyzt, said EPA’s initial draft of the Clean Power Plan was an example of policy ignoring reliability. EPA backed off from its proposed early deadline of 2020, delaying it by two years, after widespread criticism.

“That change was needed to show that your state plan is going to result in a reliable outcome,” she said.