Page 1552 – RTO Insider

April 28, 2015

MISO: Nothing Amiss in High Illinois Capacity Prices

By Chris O’Malley

MISO told Illinois officials last week that the nine-fold price increase the state experienced in this month’s capacity auction was the result of market dynamics and not any improper conduct.

“The Independent Market Monitor reviewed the offers and determined that the final results were not impacted by physical or economic withholding and other conduct prohibited by MISO’s Tariff,” Kari A.E. Bennett, MISO’s senior corporate counsel, said in an April 24 response to a request for information from the office of Illinois Attorney General Lisa Madigan.

Madigan’s staff sent a letter April 17 to MISO Executive Vice President Richard Doying and Independent Market Monitor David Patton, asking seven questions about MISO’s third annual Planning Resources Auction, which saw Zone 4, comprising much of Illinois, clear at $150/MW-day, compared with $16.75 a year earlier. The results will boost revenues for Dynegy’s coal fleet and Exelon’s Clinton nuclear plant. (See Cornucopia of Capacity at MISO Auction.)

“This year’s auction resulted in capacity prices for central and southern Illinois that are nine times greater than last year and more than 40 times greater than other zones,” Cara Hendrickson, chief of the attorney general’s public interest division, said in the letter.

Citing the “substantial impact” on Illinois ratepayers, Hendrickson asked about MISO’s market design, including limits on imports into Zone 4.

MISO said Zone 4 imported 1,568 MW of lower-cost capacity from other zones, with the balance from resources within the zone. MISO said its annual local clearing requirement study determined that Zone 4 needed at least 85% of its capacity from resources within the zone in the 2015/16 planning year.

“The value is comparable to the average of all other zones (87%) and is lower than six other zones, which required local participation of 87% or higher,” Bennett wrote.

“Different results by location and by year can occur for multiple reasons, including the impact of commercial decisions market participants make leading up to the auction and available capacity offered into the auction,” she continued. “In Zone 4, higher priced local resources were needed to meet the local clearing requirement.

“Additionally, more capacity was procured through the auction rather than by direct contracts between parties as compared to last year. This resulted in more exposure to price-sensitive capacity offers in this year’s auction.”

Red Meat for Consumer Groups

Whatever the causes, the sheer size of the increase set off a firestorm among consumer interests in Illinois.

The Chicago-based Citizens Utility Board called for a federal investigation, saying Ameren customers in central and southern Illinois will see significant rate hikes. “CUB’s rough estimate is that this increase could force consumers on Ameren’s supply rate to pay up to $150 [in capacity charges] on their electric bills over the next year,” it said.

CUB Executive Director David Kolata said the results are another sign the electricity market “is not working for Illinois consumers,” given that the state has a surplus of electricity.

Exelon, Dynegy also Miffed

Ratepayer groups aren’t the only unhappy players.

The capacity providers accused of profiting from the auction, Exelon and Dynegy, are upset at Madigan’s office.

Dynegy said that Madigan’s team told an Illinois Senate hearing last week that the company could rake in more than $200 million as a result of the auction.

That’s far from the truth, said Dynegy spokesman Micah Hirschfield. He said that Dynegy cleared only 553 MW (excluding what it needs to cover retail load obligations), meaning it will collect about $30 million.

Exelon, likewise, said speculation that it would enjoy a $50 million windfall from the auction was off base.

The company said it bid its Clinton nuclear plant’s capacity into the auction the same way it has every year.

“We bid as a price taker, meaning we would accept the auction clearing price. Because we sold some of the plant’s capacity in retail and wholesale transactions before the auction, we realized about $13 million from the auction, not upwards of $50 million as some have speculated,” Exelon spokesman Paul Elsberg said a statement.

Moreover, Exelon said the auction results were not sufficient to make the Clinton power station profitable. The utility is still pushing for the Illinois General Assembly to act on a so-called Low Carbon Portfolio Standard that would boost the competitiveness of the company’s nuclear plants.

Bluster or Substance?

Whether Madigan’s office is just fishing or will press further on the auction results is yet to be seen.

As for MISO, the RTO “looks forward to continuing the discussion with policymakers in Illinois to address any questions and concerns around the results of the Planning Resource Auction,” spokesman Andy Schonert said.

April 28, 2015

New England Governors Revise Energy Strategy

By William Opalka

New England governors last week backed away from their 2013 commitment to share the costs of new gas pipelines and electric transmission, announcing a revised regional energy strategy that gives individual states more flexibility.

A joint statement released after a summit on Thursday in Hartford, Conn., reaffirmed the governors’ commitment to regional cooperation in shifting to cleaner energy sources and expanding natural gas and electric infrastructure. However, the statement recognized the political realities of each state, all but abandoning a controversial effort to have ratepayers in all six states share in the cost of building natural gas pipelines.

“We recognize that each state may support addressing our regional energy challenge in different ways. These efforts must be done in partnership with state legislatures, and respecting the requirements of laws, regulatory proceedings, and opportunities for public participation that are unique to each individual state,” the governors said.

“It’s as if the governors had agreed on family-style meals [in 2013], but now everyone’s ordering a la carte,” The Hartford Courant observed.

New England pays the highest electric rates in the continental United States and is particularly vulnerable to price spikes in the winter. ISO-NE has created winter reliability programs to counter tight natural gas supplies, but its increasing reliance on oil-fired generation runs counter to the region’s environmental commitments, the governors said.

Vermont, New Hampshire Not Committed

In a companion document outlining short-term goals, states emphasized their project and policy preferences, with Vermont and New Hampshire pointedly not committing to sharing in new infrastructure spending.

“Vermont has not committed to share in the allocated costs of any regional gas infrastructure or electric transmission projects,” it said, but noted that the state could host transmission projects if they met its “legal criteria.”

New Hampshire noted it is a net energy exporter and said it “may host projects that meet its siting requirements and which provide benefits to the state’s residents and businesses, including our second largest industry, tourism.”

Proposed infrastructure projects are hot-button issues in both ends of New Hampshire. The Northern Pass transmission line would cut through the White Mountains to import 1,200 MW of Canadian hydropower. Part of Kinder Morgan’s proposed Northeast Energy Direct pipeline project was rerouted to existing rights-of-way in the southern end of the state to counter objections to a path in northeast Massachusetts.

Northeast Direct is one of two large-scale projects proposed to transport Marcellus Shale gas into New England from Pennsylvania. The other is a Spectra Energy project that would largely use existing rights-of-way and eventually connect with the Canadian Maritime provinces.

Connecticut Democratic Gov. Dannel Malloy, who hosted last week’s summit, also spearheaded the December 2013 meeting, which resulted in a statement that endorsed collective action. In it, the governors pledged “to advance a regional energy infrastructure initiative that diversifies our energy supply portfolio while ensuring that the benefits and costs of transmission and pipeline investments are shared appropriately among the New England States.”

The governors united behind a plan to provide a funding mechanism for natural gas pipeline expansions though a regional tax on utility bills. That plan fell apart last year when the Massachusetts legislature balked at a comprehensive package that former Democratic Gov. Deval Patrick wanted that would link gas infrastructure with a plan to expand transmission to import Canadian hydropower into the region.

Shift by New Mass. Gov.

Patrick’s successor, Republican Gov. Charlie Baker, said in a press conference after the summit that his administration supports new pipelines and transmission, a statement that The Boston Globe reported represented “a shift in tone” from Patrick’s emphasis on renewable energy.

Maine’s Republican Gov. Paul LePage, who also appeared at the press conference, praised Baker as “more collaborative and more open-minded” than Patrick, who he said was “held hostage by an ideology.”

Baker, who took office in January, said he has asked the state Department of Public Utilities to review all natural gas pipeline options. He indicated support for Spectra Energy’s plan to expand the Algonquin pipeline but would not say whether he supports Kinder Morgan’s more controversial plan, The Globe reported.

Still, some collaborative efforts continue. Earlier this year, Massachusetts, Connecticut and Rhode Island began a process that could result in joint purchases of clean energy. (See New England States Combine on Clean Energy Procurement.)

April 28, 2015June 15, 2023

Stakeholders Share Ideas on Fixing Interregional Process

By Chris O’Malley

MISO on Wednesday got an earful of stakeholder suggestions about how to spur interregional transmission projects at the seams with PJM and SPP.

They range from adopting common evaluation criteria to removing barriers for lower voltage projects to creating a new category for interregional projects.

One thing most agreed on during a “hot topics” discussion of the Advisory Committee is that the current process is not working.

Of the roughly $15.5 billion in transmission projects at MISO from 2008 to 2014, “We’ve had zero spent on interregional projects,” Kip Fox, director of asset strategy and grid development at American Electric Power, told the committee. “If this isn’t pretty clear evidence that the process is broken, I don’t know what it would be.”

“The current interregional transmission planning process has failed to meet [its] objectives and has not resulted in identifying a single interregional transmission project for approval,” agreed the Independent Power Producer sector.

Despite 12 years of joint meetings, MISO and PJM have been unable or unwilling to eliminate obstacles to cross-border projects. In February, the Federal Energy Regulatory Commission increased pressure on the two RTOs, saying it was considering taking action “to improve the efficiency of operations” at the RTOs’ seam. (See Impatient FERC Hints at Action on PJM-MISO Seams Disputes.) MISO also is working to resolve disputes with SPP.

“Even though we’ve made some progress, there still are challenges we need to work through,” acknowledged Jesse Moser, manager of strategic infrastructure at MISO.

Re-Evaluate Benefit-Cost Ratio

FERC’s Order 1000 requires interregional transmission planning but does not mandate that border-spanning projects be built.

“RTOs view compliance with Order 1000 as regularly scheduled meetings to facilitate discussion and data exchange. No plan or project is required,” said the Transmission Developer sector. “… Since 2012, over 121 project solutions along the MISO seams have been identified and summarily rejected.”

The transmission developers say MISO customers have paid more than $100 million in congestion, market-to-market costs and higher LMPs over the past four years due to inadequate transmission.

Interregional projects involving MISO and PJM must navigate three separate processes: MISO Transmission Expansion Planning regional criteria, PJM Regional Transmission Expansion Planning criteria and the cross-border process under the MISO-PJM Joint Operating Agreement.

One impediment to interregional projects, according to the developers and IPP sectors, is MISO’s requirement that interregional projects clear a 1.25 benefit-to-cost hurdle to win approval.

Both sectors say the 25% return on investment should be re-evaluated, and either lowered or broadened to capture more benefits.

“First, a project must meet the interregional criteria of providing a 25% return on investment based on a simulated adjusted production cost with perfect unit dispatch and no transmission outages,” said the developers. “Second, a project that passes the interregional criteria must now pass the regional criteria under the MTEP process using a different set of economic and powerflow models.”

MISO Director Eugene Zeltmann said he wondered whether the current ratio is detrimental to the process. But if the ratio were changed, he asked, “Would that have a deleterious effect on consumers?”

The developers say the definition of benefits should be expanded to include savings on capacity spending due to reduced transmission losses and capacity margins; avoided or delayed reliability projects; reduced emissions; and increased transmission revenues.

Reduce Voltage

Another impediment, according to some stakeholders, is that MISO has no provision for regional cost allocation for projects on low voltage transmission. MISO’s market efficiency projects are limited to projects of at least 345 kV, a much higher threshold than that of other regions.

The transmission developers said that most transmission between MISO and its neighbors is less than 300 kV. “MISO appears to be discriminating against lower-voltage projects that resolve reliability and economic solutions by making the requirement that the host zone needs to pay for the upgrade, even though the upgrade may benefit multiple zones,” they said.

The IPPs suggested projects as low as 100 kV be eligible for cost-sharing. “The current criteria was developed years before MISO’s seams expanded in the southern region,” they said.

Unify Metrics

Several stakeholder groups complained that the lack of a common set of metrics for cross-border project selection also is to blame. The Transmission Owners sector said planning should be consistent across seams and between the regional and interregional processes. “Ideally, a single transmission system model would be used in order to provide the highest level of accurate and consistent analysis,” they said.

The Transmission Dependent Utilities sector said it would support a MISO suggestion to create a new interregional project category. “It is neither productive nor efficient to consider a large number of potential candidate projects under two or three futures scenarios for which there is no consensus among the participating RTOs,” it said.

Defending Regional Differences

But in their minority comments within the Transmission Developer sector, AEP and Exelon noted that FERC has recognized the validity of regional differences in planning criteria.

The companies say using concurrent studies with identical criteria is “untenable.”

Instead, they say each RTO could post its market efficiency needs and congested flowgates and then invite stakeholders to submit regional and interregional proposals that could address those issues “more efficiently and cost-effectively than any regional proposals the RTOs may already be considering.”

Each RTO would determine what portion of its market efficiency issues is met by each of the interregional proposals. Cost apportionment would be in proportion to the benefits received by each RTO.

Backyard Projects First

MISO and PJM recently have been discussing “quick hit” flowgate projects on either side of the border that could relieve market-to-market congestion. The four low-voltage projects identified so far as most promising could generate congestion savings of more than $90 million, the RTOs said during the Interregional Planning Stakeholder Advisory Committee meeting April 14. (See Quick Hit List at PJM-MISO Seam Narrowed to 4 Projects from 39.)

April 28, 2015June 15, 2023

Cold Weather, Low Gas Prices Drive AEP Earnings

By Ted Caddell

Record cold weather and falling natural gas prices helped push American Electric Power’s first quarter earnings up 12%.

CEO Nicholas Akins said the first quarters of 2015 and 2014 were the “coldest and second-coldest winters, respectively, in our service territory during the past 35 years.”

The increased power demand, coupled with natural gas prices that dropped 43% over the first quarter of 2014, helped AEP show a profit of $629 million on revenue of $4.7 billion ($1.29/share), up from $560 million ($1.15/share) last year.

As a result of the fall in natural gas prices, AEP burned almost 15% less coal in the first quarter than a year ago.

The company also has benefited from power demand from shale oil and gas producers in the Marcellus and Utica fields.

Akins used the quarterly earnings conference call and the company’s annual meeting last week to express his continued frustration with PJM’s capacity market and repeat his call for regulatory changes in Ohio.

“It is clear that the Rube Goldberg capacity market of PJM cannot be depended upon to provide consistent revenue and price discovery to enable the long-term investment potential and maintenance of existing baseload generation. Ohio must regain control of its ability to define resources within the state,” he said.

Akins said that PJM’s capacity performance proposal “is a step in the right direction and should be a no-brainer to FERC.” (See FERC OKs PJM Request to Delay Capacity Auction.)

But he suggested AEP may not wait much longer for changes, renewing talk that the company will sell its merchant generation. It acknowledged in January that it had hired Goldman Sachs to investigate the sale of its merchant fleet in Ohio and Indiana. (See AEP Considering Sale of 8,000 MW in Ohio, Indiana.)

“Right now, there is no support for long-term investment in the state of Ohio, and we’re trying to get that fixed from an energy-policy perspective,” Akins told reporters following the company’s annual shareholder meeting Tuesday. The company failed in February in its bid to secure regulatory approval for a “guaranteed price” power purchase agreement for one of its coal-fired plants. It has another case pending for four more of its plants. (See “PUCO Rejects AEP’s Guaranteed Income Plan for Coal Plants” in State Briefs, March 2, 2015.)

Akins didn’t seem optimistic about the chances for winning regulatory changes. “At this point, looking at it, you would need to lean toward that direction [of selling the unregulated plants] because there clearly is volatility in that business, and it’s very difficult to invest,” he said.

April 28, 2015June 15, 2023

Another Cold Winter Helps Michigan Utilities in Q1

By Chris O’Malley

Extreme cold helped drive first-quarter earnings at two of Michigan’s largest gas-electric utilities, though neither DTE Energy nor CMS Energy enjoyed quite the bump it did during the polar vortex last year.

Moreover, operating revenue at DTE Energy fell 24% on losses in its energy trading business. DTE’s first-quarter earnings of $273 million ($1.53/share) compare to $326 million ($1.84/share) in the first quarter of 2014. Per-share earnings exceeded a $1.52 forecast by analysts polled by Thomson Reuters.

Operating revenue of $2.98 billion was down from $3.93 billion a year earlier and less than the $3.53 billion analysts had forecast.

In the first quarter, DTE’s energy trading unit lost $9 million, versus a profit of $42 million in early 2014. The company cited mark-to-market adjustments.

Operating earnings for DTE Electric were flat, at $136 million. DTE Gas earnings of $111 million were down 14%, from $129 million during the first quarter 2014 polar vortex.

During a conference call with analysts, DTE Energy executives held firm on full-year earnings-per-share estimates of $4.48 to $4.72.

“We’re off to a strong start across our portfolio of businesses,” Chief Financial Officer Peter Oleksiak said.

First-quarter net income of Jackson, Mich.-based CMS Energy fell nearly 1% to $202 million ($0.73/share). That compares with $204 million ($0.75/share) in the first quarter of 2014.

On a weather-normalized basis, however, earnings per share were 7% more than last year’s first quarter, CFO Tom Webb told analysts during a conference call.

CMS said it was holding to its 2015 earnings-per-share guidance of $1.86 to $1.89, in line with the company’s annual adjusted growth goal.

April 28, 2015June 15, 2023

Federal Briefs

The Bureau of Land Management is taking public comments on a gas processing plant that QEP Resources Inc. wants to build near LaBarge, Wyoming. The plant would process production from nearby natural gas wells, separating the raw feed gas into refined helium and marketable carbon dioxide and methane streams.

Refined helium product would be delivered to markets by commercial truck. Excess nitrogen would be vented to the atmosphere. Waste streams of hydrogen sulfide would be injected into a sour gas disposal well currently planned to be drilled close to the plant. Another well would be used for injecting waste water and four wells would be used to inject unsold carbon dioxide.

The plant would include about 16 miles of methane and CO2 pipelines, 13 miles of 230-kV transmission line and a substation. While some of the 355 acres for the project are on federal and state land, the majority is on land owned by QEP. The BLM is taking comments until May 20. Comments may be emailed to the bureau.

More: PennEnergy, BLM

Lawmakers Introduce Bill Targeting “Absurd” Fossil Fuel Tax Breaks

Sen. Bernie Sanders (I-Vt.) and Rep Keith Ellison (D-Minn.) introduced a bill that would kill tax breaks for fossil-fuel companies. They said the bills could save $135 billion over 10 years.

“At a time when scientists tell us we need to reduce carbon pollution to prevent catastrophic climate change, it is absurd to provide massive taxpayer subsidies that pad fossil-fuel companies’ already enormous profits,” Sanders said in a statement.

The “End Polluter Welfare Act” target federal subsidies for the oil, natural gas and coal industries, as well as grant programs for rail companies. It also calls for an increase in the royalties that coal, oil and gas companies pay for extracting oil and gas from federal land.

More: The Hill

No Changes Needed At Fuel Plant, NRC Says

The Nuclear Regulatory Commission gave a clean bill to a nuclear-fuel processing plant in Erwin, Tenn. The NRC’s two-year- licensee performance review at the Nuclear Fuel Services facility found that the plant was operating at a satisfactory level of safety and security.

The review singled out an incident in which an employee propped open two valves with a tool rather than holding them open according to regulations, but the infraction was deemed a low-risk event, the commission said. A separate chemical spill at the plant, earlier this spring, is still under investigation.

Nuclear Fuel Services is a subsidiary of Babcock & Wilcox Nuclear Operations Group.

More: WJHL-TV

FERC to Conduct Environmental Study Of Tennessee Gas Conversion Plan

The Federal Energy Regulatory Commission will prepare an environmental assessment of a plan by Kinder Morgan’s Tennessee Gas Pipeline to convert an existing pipeline to transport natural gas liquids collected from shale gas fields. The line was originally built about 70 years ago to move natural gas. It runs 256 miles through 18 Kentucky counties, into Tennessee. The current south-to-north flow will be reversed.

An environmental assessment could take as long as six months, and will look at construction methods, materials, and the pipeline path.

More: Lexington Herald-Leader

Environmental Group Opposing Ameren Nuke Plant License Extension

CallawaySourceNRC — Callaway Nuclear Station (Source: NRC)

A Missouri environmental organization is calling for the Nuclear Regulatory Commission to reverse its decision to grant a license extension to Ameren Missouri’s Callaway nuclear station. The Missouri Coalition for the Environment is appealing the NRC’s decision to extend Callaway’s operating license until 2044. The group cites pending legal challenges that could have an impact on the case.

More: St. Louis Dispatch

NRC Gives Peach Bottom Highest Rating in Review

Peach Bottom Atomic Power Station (Source: Exelon)

Exelon Nuclear’s Peach Bottom Atomic Power Station received the highest safety rating after a review by the Nuclear Regulatory Commission. The NRC announced its finding at a public forum held last week. The NRC senior resident inspector for the plant, Sam Hansell, told a small crowd that the plant on the Susquehanna River had only minor violations in 2014. “Peach Bottom is in a group of top-performer plants,” he said. “They get credit for running their plant safely.”

More: The Baltimore Sun

April 28, 2015January 23, 2024

MISO to Consumer Sector: No Money for You – UPDATED

By Chris O’Malley

CARMEL, Ind. — MISO has declined a request by the Public Consumer Advocates sector for $200,000 to help cover its legal costs in a fight over MISO transmission owners’ return on equity.

The decision was announced Wednesday at the MISO Advisory Committee meeting.

“We don’t have a mechanism to send them money,” said MISO General Counsel Stephen Kozey, adding that there was no show of stakeholder support for such funding.

The Public Consumer Advocates sector consists of both non-profit groups and government agencies that represent consumers in utility cases before state regulators.

It decided to enter the ROE battle — the sector’s first-ever litigation in a federal rate case — after settlement talks ordered by the Federal Energy Regulatory Commission between industrial customers and TOs broke down last year.

The consumer sector made the funding request at the Advisory Committee in February, saying it lacks the deep pockets for legal costs.

Robert Mork, deputy consumer counselor for the Indiana Office of Utility Consumer Counselor, said the consumer advocates have been supportive of MISO over the years. “We have to say we’re surprised and disappointed by MISO’s decision on this,” Mork said.

Appeal to Board

Mork raised the issue again during Thursday’s Board of Directors meeting, urging the board to ensure that ratepayer concerns are protected.

Mork said a letter Kozey sent to the advocates explaining MISO’s rejection “seemed to rely primarily on tallying up the sectors’ responses, and not in a very nuanced way at that.”

The letter reported that five sectors in addition to the consumer advocates commented on the request, with four — the Power Marketers and Brokers, Transmission Developers, Transmission Dependent Utilities and Transmission Owners — in opposition.

The Organization of MISO States took no position, despite acknowledging that the case “may have significant impact on customers throughout MISO, and it is valuable to have diverse viewpoints, including consumer advocates, represented before FERC.” Texas and Louisiana abstained from OMS’ vote.

Mork said Kozey’s response “raises concerns to our sector that MISO may not adequately appreciate its independence and stakeholder responsiveness” obligations under FERC Order 719, he said. “We would respectfully suggest that MISO needs to show that it understands that it has a clear obligation to look beyond the particular [views] of the sectors and to consider what is in the overall interests of the organization and the public.”

Mork added that his sector would continue to engage with MISO.

“We all have a shared interest that MISO-related issues appear to be dealt with so as to ensure the legitimacy of MISO and its processes.”

Mork didn’t elaborate on the group’s response to the funding denial but said that the consumer sector would have further discussions with MISO, OMS and FERC.

Neither any of the board members nor any stakeholders made comments on the issue.

MISO industrial customers initiated the ROE dispute last year, contending that transmission operators’ current base ROE — 12.38% except for American Transmission Co., at 12.2% — is too high (EL14-12). On April 3, the consumer advocates asked FERC for approval to amend the group’s intervention by adding allies from Arkansas, Kentucky, Louisiana, Montana and Illinois. (See MISO TOs Seek Base ROE of 11.39%.)

April 28, 2015June 15, 2023

NERC: Industry Needs More Time to Meet Clean Power Plan

By William Opalka

The U.S. electric industry will face reliability concerns in four years if the interim goals of the Environmental Protection Agency’s Clean Power Plan aren’t relaxed, the North American Electric Reliability Corp. said last week.

NERC released a reliability assessment of the CPP Tuesday that concludes EPA’s proposed 2020 targets — 80% of the total CO₂ emission reductions the agency seeks — can’t be reached in several regions.

The 69-page report provides additional ammunition for critics who have called for changes to the interim goals and the provision of a reliability “safety valve.” The report is NERC’s second on the impact of the EPA plan. Its initial review, released in November, examined EPA’s assumptions and provided a broad view of potential reliability risks. (See MISO, SPP: EPA Clean Power Plan Threatens Reliability, Needs Longer Compliance Schedule.)

Scenarios Analyzed

The new report examines in detail how the plan would impact the generation mix and resource adequacy. It also provides a high-level analysis of transmission needs and identifies major shortfalls of reactive power needed to maintain voltage stability. In addition to a business-as-usual baseline, NERC compared a scenario assuming state-by-state compliance with one allowing for regional compliance with interstate trading. It also conducted sensitivities on the impact of lower gas prices.

NERC concludes the plan will accelerate the transition in the generation mix as natural gas, wind and solar power replace coal. The report predicts about 60 GW of natural gas-fired generation will be added by 2020, rising to 80 GW by 2030. Coal retirements are projected to total at least 18 GW by 2020 and an additional 18 GW by 2030.

Much of the remaining coal fleet will have to change from baseload to seasonal and peaking use, making the plants less economic, NERC said. Between 14 GW and 22 GW of coal plants remaining in service after 2020 will be at risk because they would be operating at capacity factors of only 11% to 19%.

The report warns that new generators will be needed before the transmission and pipeline infrastructure to support them can be built. While most combined-cycle gas turbine plants go from conception to operation in an average of 64 months, transmission infrastructure can take from five to 15 years. Local and regional pipeline infrastructure will also need to be in place to deliver gas to the new plants.

“More time is needed to develop coordinated plans for this shift in generation and corresponding transmission reinforcement,” said John Moura, director of reliability assessments.

NERC noted there are regions where compliance will be easier, but says New York and the New England states in the Northeast Power Coordinating Council will need more than 7 GW of new capacity by 2020, with ERCOT in need of 11 GW over the same time frame.

The report also predicts major changes in transmission flows, with Canada tripling its exports to the U.S. and PJM-East shifting from being a net importer to a net exporter as generating units in Regional Greenhouse Gas Initiative states become more competitive with the imposition of carbon pricing nationwide.

MISO Central would reduce its exports to MISO North due to cheaper imports from Canada while increasing its exports to MISO South.

EDF Challenges Report

The Environmental Defense Fund disputed the report’s conclusions.

“NERC’s modeling uses unrealistic assumptions that are contradicted by what’s happening on the ground today,” Cheryl Roberto, EDF’s associate vice president of clean energy said in a statement.

NERC “fails to capture the great innovation happening now – with major investments in renewables, efficiency, natural gas and transmission infrastructure,” Roberto said. “NERC’s report also assumes flat-footed regulators, when the truth is regional and state-level regulators have repeatedly demonstrated they are up to the task of planning for future power needs. In short, NERC’s assessment does not take into account the transformation unmistakably underway in our electric system.”

April 28, 2015June 15, 2023

PJM Considering Change to Day-Ahead Deadlines in Response to FERC Gas Schedule Order

By William Opalka, Chris O’Malley and Rich Heidorn Jr.

PJM is considering changing its day-ahead market schedule in response to the Federal Energy Regulatory Commission’s April 16 ruling revising the interstate gas nomination timeline.

Other RTOs’ reactions varied, with ISO-NE saying it has no plans to change its schedule and NYISO looking to respond to its neighbors. MISO stakeholders will discuss the issue Friday, while an SPP task force is expected to make recommendations on any changes by July.

FERC moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (12:30 p.m. to 2 p.m. ET). It also added a third intraday nomination cycle (RM14-2). (See FERC Approves Final Rule on Gas-Electric Coordination.)

In response, PJM is considering moving up its day-ahead schedule by three hours, Adam Keech, senior director of market operations, told the Markets and Reliability Committee on Thursday.

PJM’s day-ahead market results currently are published at 4 p.m. ET, which would not provide enough time for selected generators to purchase gas, Keech said.

PJM is proposing that day-ahead offers close at 9:30 a.m. ET, with results published no later than 1 p.m. That would allow at least one hour for gas generators selected to run the next day to purchase fuel before the timely nomination cycle deadline.

The rebid period and reliability unit commitment (RUC) also would be moved up, running from 1 p.m. to 4:30 p.m., with results published by 6 p.m., allowing at least one hour for gas nominations before the evening nomination cycle deadline, which FERC left unchanged.

The changes would condense the day-ahead market solution window to 3.5 hours.

Joe Wadsworth of Vitol asked if PJM would be coordinating its changes with neighboring regions. He said moving PJM’s day-ahead deadline to 9:30 a.m. could inhibit trading with NYISO, which publishes its day-ahead results at about 9:30 a.m. That could hurt day-ahead convergence along the NYISO-PJM seam, he said.

Wadsworth said PJM also needs to consider that liquidity in the next-day gas markets sometimes doesn’t occur until after 10 a.m. on high gas-demand days. In such circumstances, there may be little or no natural gas price transparency prior to PJM’s day-ahead market bid deadline, he said.

Ed Tatum of Old Dominion Electric Cooperative suggested PJM coordinate the changes through the ISO/RTO Council and consider changing the start of the electric day.

Keech said FERC’s order neither mandates nor precludes changes to the electric day.

Keech’s comments came during a first read of a proposed problem statement to respond to the FERC order. Although the initiative won’t come up for a vote until the May 28 MRC meeting, PJM will conduct an educational session following the May 6 Market Implementation Committee meeting.

PJM and other regions must make compliance filings — adjusting their tariffs to comply with the final rule or explaining how their current rules are compliant — by July 23.

NYISO

“Because electricity markets are interdependent, the NYISO’s response to FERC’s order will need to account for its neighbors’ compliance efforts,” NYISO spokesman David Flanagan said. “If no changes are determined to be necessary, FERC’s decision will provide New York generators an additional hour-and-a-half to nominate the gas they require following the posting of the NYISO’s day-ahead market. FERC’s order also will increase the gas procurement flexibility available to New York generators that participate in the NYISO’s real-time market.”

MISO

MISO spokesman Andy Schonert said the RTO is “working internally and with stakeholders to figure out how we will respond to FERC’s order.” The Electric and Natural Gas Coordination Task Force will discuss the issue in a meeting May 1.

SPP

SPP spokesman Tom Kleckner said the RTO’s Gas Electric Coordination Task Force discussed the FERC ruling at a meeting Thursday and will be making a recommendation to SPP’s Board of Directors at the board’s July meeting.

“The [task force] is evaluating what changes can be made to the day-ahead and reliability unit commitment timelines,” Kleckner said. “It will be up to our stakeholders to make any changes to our timeline that are presented to the board.”

ISO-NE

ISO-NE, which shifted its day-ahead market schedule two years ago to align with the natural gas trading day, believes it is already in compliance with the FERC rule, spokeswoman Marcia Blomberg said.

“However, we are very disappointed at the decision not to change the gas day,” Blomberg said. “We continue to believe it would have been a material improvement to reliability. Without the change, obtaining fuel in order to meet their obligations will be more challenging for generators during upcoming winters. We are supportive of the change to the timely nomination cycle, which will help owners of gas-fired generators incrementally by improving their ability to timely nominate and schedule gas.”

April 28, 2015

PJM Members Tighten Lost Opportunity Cost Rules; Tech-Specific Eligibility Retained

By Suzanne Herel

WILMINGTON, Del. — PJM stakeholders last week approved tighter rules on generator lost opportunity costs but rejected a proposal to limit eligibility to the most flexible combustion units.

The rules concern compensation for combustion turbines that are scheduled in the day-ahead energy market but not committed in real time.

The vote by the Markets and Reliability Committee on Thursday was a partial setback for PJM and Independent Market Monitor Joe Bowring, who said current rules provide incentives for units to offer and clear in the day-ahead market but not in the real-time market.

PJM and the Monitor won a change preventing combustion turbines from receiving start-up and no-load costs when they do not run in real time — correcting what Bowring called “an algebra mistake” that resulted in generators receiving payments for costs they did not incur.

The change — including no-load and start-up costs as avoided costs in LOC calculations — was a reform the Monitor had sought since 2012. PJM has estimated the change could reduce LOC payments by about $40 million annually.

‘2×2’ Rule Rejected

The Energy Market Uplift Senior Task Force also had approved a proposal that would have allowed only the most flexible “2×2” CTs — those with start-up plus notification times and minimum run times of two hours or less — to receive lost opportunity costs if they are not dispatched in real time after clearing the day-ahead market.

Resources with start-up plus notification times or minimum run times of more than two hours would not have received lost opportunity payments unless PJM barred them from running in real time to avoid transmission overloads or other reliability problems.

But the task force’s proposal received less than 60% support in a sector-weighted vote of the MRC, short of the two-thirds minimum for passage.

An alternate motion that retained the current technology-specific LOC eligibility rules — combustion turbines and combined-cycle plants operating in simple-cycle mode — was then approved with nearly 92% support and a round of applause.

The MRC last month tabled the task force’s proposal, sending it back for more discussion, after some members, including Ed Tatum of Old Dominion Electric Cooperative (ODEC), complained that the 2×2 requirement was too restrictive. (See PJM Tables Rule Change on CT LOCs.)

Several proposed amendments emerged from the task force’s April 17 meeting: one by Dominion Resources, allowing for start-up costs to be paid if a unit operates in real time at PJM’s direction during any portion of its “temporally contiguous” commitment period; one from PJM clarifying the definition of “temporally contiguous”; and one from ODEC that would have extended LOC eligibility to 2×5 units with minimum run times of up to five hours.

Economic Choice

“We believe units with greater than a two-hour minimum run time are valuable to dispatch,” Tatum said. “We should be making decisions on units’ capability and not on an algorithm’s limitations.” (See PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs.)

Bowring disagreed. “I don’t agree there is any physical basis for any minimum run time. It’s not required by manufacturers … it’s typically an economic choice,” he said. “I would suggest, if anything, that two hours is too long, not too short.”

Bowring added, “Part of the reason we got into this problem in the first place is PJM wasn’t really looking out four or five hours. Five hours is nowhere near flexible.”

Neither amendment by Dominion nor ODEC was cleared as “friendly,” so membership voted on the main EMUSTF proposal, which failed.

Susan Bruce of the PJM Industrial Customers Coalition then made what became the winning proposal, suggesting that the language regarding LOC eligibility be returned to the status quo and considered for approval along with Dominion’s amendment and PJM’s definitional clarification.

“My understanding is that [the 2×2 issue] was a bit of a surprise to some people,” she said. “That will move us past this issue.”

PJM’s Adam Keech, director of wholesale market operations, said that regardless of a mandated minimum run time, PJM will be making procedural changes “because we think we can do better,” noting that the RTO paid $25 million in lost opportunity costs in February. “We’re going to look at less flexible CTs, with lead times eight to 10 hours, and run them more often,” he said.

Because the less flexible units will retain their LOC eligibility, committing them in real time will ensure they are paid based on LMPs instead of being compensated via uplift.

Because the day-ahead payments to the units are a sunk cost, the less flexible units in many cases become essentially a “free resource” to PJM operators, Bowring explained.

After the meeting, Tatum said he was pleased with the vote. “We’re good for now — until the next shoe drops,” he said.