Page 1566 – RTO Insider

April 21, 2015June 15, 2023

ITP10 to Include 3 Scenarios for Clean Power Plan

By Rich Heidorn Jr.

TULSA, Okla. — SPP’s next 10-year transmission plan will consider three future scenarios to assess the potential impact of the Environmental Protection Agency’s Clean Power Plan, members agreed after a lengthy debate last week.

The Markets & Operations Policy Committee decided the 2017 Integrated Transmission Planning 10-Year Assessment will include one scenario assuming regional compliance with the EPA rule and one assuming state-by-state compliance. The third scenario will be a business-as-usual case that assumes the EPA rule is abandoned — due, for example, to a legal challenge or a change in leadership at EPA after the 2016 presidential election.

clean power plan — SPP’s 2015 10-year plan compared a business-as-usual case, which projected the need for 15.3 GW of new conventional generation at 60 sites, with a decreased baseload scenario, which projected a need for 21 GW of new conventional generation at 82 sites. The latter scenario assumed the retirement of all coal units less than 200 MW and a 20% reduction in hydropower capacity due to drought.

EPA plans to issue the final rule this summer. It is intended to reduce power generation CO₂ emissions by 30% from 2005 levels.

SPP this month released a study estimating the RTO could comply with the rule through a regional approach that includes a $45/ton carbon adder and 7.8 GW of additional generation, most of it wind. The study estimated an annual cost of $2.9 billion in increased energy costs and capital spending for new gas and wind generation. It did not evaluate additional transmission that may be needed, an element ITP10 will seek to quantify. (See SPP: $45/ton Adder, Wind, Gas Meets EPA Carbon Rule.)

The Economic Studies Working Group had recommended use of three futures, including one that assumed increased load growth as a result of the elimination of the Clean Power Plan. MOPC members amended that to assume normal load growth — creating a business-as-usual scenario as a comparison with the regional and state-by-state compliance schemes.

Members first rejected a proposal to include a fourth future that included an “extreme” EPA final proposal. It won only 41% support. A second vote limiting the study to the regional and state compliance scenarios but allowing the working group to seek approval of a third future, also fell short at 57%.

Fundamental Questions

The debate over the study revealed fundamental questions over the RTO’s planning strategy.

“Once again we are doing the absolute minimum and not looking at the long-term future,” said Kristine Schmidt, vice president of regulated grid development for ITC Holdings.

Board of Directors Vice Chairman Harry Skilton said the 18-month timeline for completion of the study is too long. “This is unbelievably ridiculous that it takes this long,” he said.

Lanny Nickell, vice president for engineering, said the length of the study process reflects the incorporation of stakeholder input. “We have a very open and transparent stakeholder process,” he said. “That is very valuable, but it takes time.”

The debate continued during Wednesday’s meeting of the Strategic Planning Committee, as Skilton, Board Chairman Jim Eckelberger and member Phyllis Bernard called for changes.

Eckelberger said MOPC’s debate over whether it should spend $270,000 in planning staff salaries for a fourth future was shortsighted considering the at least $8 billion the RTO expects to spend on new transmission.

“We’ve got this all backwards,” he said. We’re “trying to put the right lines in the right place. We don’t want to misspend money. We don’t want to get it wrong. We want to have as much foresight as possible. We have not built the robust capability within SPP to get this right — and it’s one of our primary responsibilities.”

Steve Gaw, representing The Wind Alliance, said SPP needs information on a variety of generation sources it may call on under the EPA plan. “You can’t get there with two futures — or with three if one of them is a business-as-usual case.”

Skilton and Bernard also called for a broader range of scenarios.

“I’m not in favor of planning too far out, but I’m in favor of planning much more broadly — casting a really wide net,” she said. “But don’t necessarily try to project it too far forward because we don’t know what’s coming.”

Skilton said the RTO also should seek a shorter planning cycle — ideally six months instead of a two years.

“People have told me six months is impossible,” he acknowledged. “We may not get to six months but we won’t be at 24.”

Nickell said he would relay the board’s thoughts to the newly formed Transmission Planning Improvement Task Force, which has been charged with producing “more progressive, forward-thinking, regional planning processes that are more responsive” to the continued growth of SPP’s transmission system and markets in response to federal and state environmental regulations and reliability rules.

“If I could boil it down,” said Nickell, “you all said you want it bigger, better, quicker… more agile.”

April 21, 2015June 15, 2023

‘Quick Hit’ List at PJM-MISO Seam Narrowed to 4 Projects from 39

By Chris O’Malley

MISO and PJM said last week they will pursue four “quick hit” flowgate projects that show promise in relieving market-to-market congestion.

The four low-voltage projects could generate market-to-market congestion savings of more than $90 million, based on modeling of day-ahead and balancing congestion during 2013-2014, the RTOs said during the PJM-MISO Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting on April 14.

The four projects were selected from a list of 39 flowgates with $408 million in historical congestion that IPSAC studied. MISO said it is still awaiting responses from transmission operators regarding five other projects that are still possible quick-hit projects. (See MISO, PJM Ponder List of ‘Quick Hit’ Upgrades.)

Flowgates that showed significant day-ahead and balancing congestion in 2013 and 2014, and flowgates that caused auction revenue rights infeasibilities, were included. Solutions had to be completed and provide a payback on investment quickly. Greenfield projects were not considered.

Eric Laverty, MISO director of sub-regional planning, said most of the potential flowgate projects that were studied should be disqualified because they experienced no recent congestion, they had already been identified for in-service upgrades or they did not represent a solid business case.

The four projects chosen were:

Benton Harbor-Palisades, an American Electric Power-Michigan Electric Transmission Co. tie line that would receive terminal upgrade equipment. Congestion relief: $61.5 million.
Beaver Channel-Sub 49 161-kV, consisting of a SCADA equipment upgrade. Congestion relief: $6.9 million.
Michigan City-Laporte 138-kV line upgrades. Congestion relief: $2.7 million. Day-ahead relief: $23 million.
Cook-Palisades 345-kV, consisting of upgrading terminal equipment. Congestion relief: $31.5 million.

“We believe there’s a business case for these four projects,” Laverty said.

Laverty said the cost of the four projects ranged from “tens of thousands of dollars” to “low millions.” The only project with a specific price was the $2.5 million Michigan City-Laporte flowgate upgrade.

Committee members said they were confident the upgrades would not simply move congestion to other parts of the RTOs’ footprints.

Chuck Liebold, PJM’s manager of interregional planning, said the RTOs modeled not only historical congestion patterns but also what effects the upgrades would have in relieving congestion on the seam. “In the cases we recommended, the upgrades were very successful at that,” Liebold added.

Both RTOs are talking with transmission owners about the possibility of making upgrades and about who will foot the bill. The committee said it would welcome ideas about cost-sharing.

Stewart Bayer, transmission policy engineer at Northern Indiana Public Service Co., suggested that the RTOs address the issue of cost allocation first, before transmission operators make upgrades. “I don’t know how willing we are to proceed without knowing who’s paying for it,” he said.

April 17, 2015

FERC Approves Final Rule on Gas-Electric Coordination

By Ted Caddell

The Federal Energy Regulatory Commission on Thursday approved a rule to improve coordination of the wholesale natural gas and electric market schedules, adopting two gas scheduling changes but declining to move the start of the gas day to 4 a.m. CT from 9 a.m. CT (RM14-2).

Order 809 revises the interstate gas nomination timeline, moving the timely nomination cycle deadline for scheduling gas transportation to 1 p.m. CT from 11:30 a.m. CT. It also adds a third intraday nomination cycle, which should allow shippers to better adjust to changes in demand.

Thursday’s order was a win for the Natural Gas Council, which last year rejected an earlier start time, saying it would cause safety and contractual problems. The group represents nearly all the companies that produce and deliver gas, including members of the American Gas Association, America’s Natural Gas Alliance, the Independent Petroleum Association of America, the Interstate Natural Gas Association of America and the Natural Gas Supply Association.

The failure to reach consensus between the electric and natural gas industries was noted in a FERC staff presentation at the commission’s open meeting Thursday. “The … final rule finds that there has not been a showing that the benefits of changing the nationwide gas day from 9 a.m. CT to 4 a.m. CT sufficiently outweigh the potential adverse operational and safety impacts and costs of making such a change,” staff said.

Growing Pains

gas-electric — Facing opposition from pipeline operators, FERC retreated from its earlier proposal to move up the start of the gas day.

The growth in natural gas-fired generation has strained pipeline capacities and provided operational challenges to grid operators. Two issues were spotlighted: communications between generators and natural gas transmission operators, and gas-electric scheduling.

In November 2013, the commission approved a rule allowing gas pipeline operators to exchange non-public operational information with RTOs. (See FERC OKs Gas-Electric Talk.)

A 2013 report by the North American Electric Reliability Corp. said that the disparity in schedules meant that “electric generator nominations, with their relatively large gas loads, are based upon estimates by the individual fuel planners of each Generator Owner (GO) between 24 and 36 hours in advance. The issue could be magnified when scheduling on a Friday, since gas markets are closed for the weekend.”

The new rule “illustrates how the commission can engage with industry and stakeholders in a collaborative process to offer real improvements in our natural gas and electricity markets,” Commissioner Cheryl LaFleur said in a statement.

The American Gas Association, which represents more than 200 local distribution companies, praised the ruling.

“I am pleased to see that FERC will maintain the 9 a.m. CT start time, a positive step that recognizes what is in the best interest of both gas and electric customers,” CEO Dave McCurdy said. “We appreciate FERC’s attention to the coordination between gas and electric systems, and believe this is a critical issue that needs attention, but changing the gas day was not a step that would have ultimately improved this coordination.”

Retreat

But Thursday’s order was a retreat from the commission’s March 2014 Notice of Proposed Rulemaking, which proposed the 4 a.m. start time. (See FERC: Six Months to Move Gas, Electric Schedules.)

The commission approved the NOPR on a 3-1 vote with LaFleur, Commissioner Philip Moeller and former Commissioner John Norris in support. Commissioner Tony Clark dissented, saying he wanted to give the industries more time to reach consensus. Since then, the commission has added Commissioners Norman Bay and Colette Honorable.

The rule becomes effective 75 days after publication in the Federal Register. Each ISO and RTO must come up with tariff revisions to either coordinate its day-ahead market with gas pipeline scheduling changes or show why changes shouldn’t be implemented.

April 16, 2015

FERC Rejects Ginna Rates, Orders Settlement Proceeding

By William Opalka

The Federal Energy Regulatory Commission on Tuesday rejected the rate schedule proposed for a struggling nuclear power plant needed for reliability in western New York and ordered hearing and settlement proceedings (ER15-1047).

The commission approved only part of the reliability support services agreement for the R.E. Ginna nuclear plant between Rochester Gas & Electric and Exelon’s Constellation Energy Nuclear Group, the plant’s owner, which is also under review by the New York Public Service Commission.

The commission rejected the proposal that Ginna receive 15% of its NYISO market revenues, saying it “does not comport with the general principle that rates under [a reliability-must-run] agreement must be cost-based.”

“A compensation structure that provides for both a cost-based monthly fixed rate (whether going-forward costs at the low end, or a full cost of service at the upper end) and a share of market revenues does not meet this principle, as the revenue-sharing provision is not cost-based and may allow for Ginna to earn more than its full cost of service,” FERC wrote.

The commission approved a provision that would require Ginna to repay capital investment costs it recovers under the RSSA if it were to return to the market after the agreement’s expiration.

The capital recovery balance would range between $20.1 million and $65.3 million depending on when it was invoked, “a sufficient disincentive” to dissuade Ginna from “toggling” between compensation under the RSSA and the NYISO markets, the commission said.

FERC thus excluded the issue of toggling from the hearing but said it may address whether the amounts in the capital recovery balance are just and reasonable.

FERC said it would allow about 45 days for settlement discussions before scheduling a hearing.

The RSSA was ordered by state officials and is scheduled to be retroactive to April 1, once approved by regulators. The agreement would cost about $175 million a year and be effective through late 2018. Ginna says it lost more than $150 million between 2011 and 2013.

The immediate effect of FERC’s order is that a procedural case before administrative law judges of the PSC has been slightly delayed. The PSC ordered initial “issue statements” by April 15 in a review of the rate impact on consumers, but that has been pushed back until April 22. (See NYPSC Rejects Opponents’ Request for More Time in Ginna Rate Review.)

FERC has ordered NYISO to standardize its procedures for RMR agreements, of which the proposed Ginna deal is the most recent. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)

As a result, Tuesday’s order also struck a provision allowing an extension of the agreement beyond 2018. “If there is a future reliability need for the RSSA beyond its initial term, Ginna will be subject to the procedures that NYISO establishes, and the commission approves, in response to the NYISO RMR order,” FERC wrote.

April 15, 2015

Cornucopia of Capacity at MISO Auction, but Famine Could Follow as Coal Plants Retire

By Chris O’Malley

MISO completed its third annual Planning Resource Auction on Tuesday, with prices falling in most zones, while the Illinois zone saw a large jump that will boost revenues for Dynegy’s coal fleet and Exelon’s Clinton nuclear plant.

With 136,359 MW committed, MISO said it has adequate capacity for the 2015/16 planning year beginning June 1 but acknowledged that the 2016/17 period could see capacity shortfalls amid the ongoing retirement of coal-fired generation.

Most of that — 122,965 MW — was generation resources. The remainder consists of 5,938 MW of demand resources, 3,986 MW of behind-the-meter generation and 3,469 MW of external resources.

The auction resulted in a slight increase in Zone 1, big drops in Zones 2-3 and 5-9 and a nine-fold increase in Zone 4:

Zones 1-3 and 5-7, consisting of MISO North/Central but excluding Illinois, cleared at $3.48/MW-day. That compares with $3.29 in Zone 1 and $16.75 in Zones 2-3 and 5-7 in 2014/15.
Zone 4, comprising much of Illinois, cleared at $150/MW-day, compared with $16.75 a year earlier.
Zones 8-9, comprising MISO South, cleared at $3.29/MW-day, compared with $16.44 a year earlier.

“While Dynegy is clearly the largest beneficiary of the MISO capacity auctions results, Exelon also gains via ownership of its Clinton nuclear asset,” UBS analyst Julien Dumoulin-Smith said in a report last week.

Dynegy said in a press release that its 4 GW coal-fired Illinois Power Holdings fleet cleared 1,864 MW at $150/MW-day, including 1,709 MW to cover retail load obligations. Its separate 2,980-MW “coal segment” also cleared 398 MW at that price.

Exelon spokesman Paul Elsberg confirmed that the Clinton plant cleared the auction but said the increase was insufficient to make the plant profitable. Exelon has been pushing legislation that would charge Illinois electricity users a fee to ensure the continued operation of Clinton and two other unprofitable nuclear generators. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)

“The auction results reduce Clinton’s economic losses, but the plant remains uneconomic and may prematurely shut down absent Illinois legislative changes to outdated policies that do not allow nuclear energy to compete on a level playing field with other zero-carbon resources,” Elsberg said in a statement.

“The wholesale price increases from the auction are small compared to the price spikes that would occur if Clinton is forced out of the market. According to the Illinois Commerce Commission and grid operators, closing the Clinton plant alone would cause wholesale energy prices to rise by $240 million to $340 million annually.”

Clinton would earn $58 million in capacity revenue if it bid and cleared all of its 1,065 MW capacity. Elsberg declined to say how much capacity Clinton cleared.

MISO said market participants lowered offers in most zones as a result of small changes in the balance of resources and load and an increase in Fixed Resource Adequacy Plans (FRAPs).

Zone 4’s $150 clearing price resulted from less self-scheduling and the submission of “more economic, price-sensitive offers,” MISO said.

Although total offers exceeded the zone’s local clearing requirement of 8,852 MW by 2,300 MW, only 838 MW was offered through FRAPs, 9% of the LCR.

In contrast, FRAPs represented more than 90% of LCRs in Zones 1 (Minnesota, North Dakota and western Wisconsin) and 2 (eastern Wisconsin, and Upper Michigan).

Richard Doying, MISO’s executive vice president of operations and corporate services, said the voluntary auction’s “certainty and transparency” is “vital given the challenges we face with potential capacity shortfalls starting in the 2016/17 planning year.”

MISO is facing a reduction in coal-fired capacity due to retirements of aging coal plants squeezed by the Environmental Protection Agency’s tightening Mercury and Air Toxics Standards and low-cost gas-fired generation.

Coal-fired generation in MISO is expected to decrease from 46% of total installed capacity in 2013 to 36% in 2020, according to a whitepaper MISO released in March. EPA’s proposed Clean Power Plan, which would require a 30% reduction in CO₂ emissions from existing generators, is expected to further thin coal fleets.

Late last month MISO underscored the problems that coal plant retirements will cause in its 15-state region. Launching its first in a series of stakeholder workshops during the next 18 months dedicated to improving resource adequacy, MISO said its planning reserve margin requirement — peak demand plus the planning reserve margin — could dip below its target as early as 2016.

As the reserve margin declines, MISO may have to dispatch seldom-used capacity. That could include greater use of load-modifying resources, such as factories that can reduce usage by adjusting production schedules and commercial buildings that reduce air conditioning.

MISO has not called on those resources since 2006.

April 14, 2015

MISO Staff Hold Firm in Support of Entergy Out-of-Cycle Request

By Chris O’Malley

Responding to a new round of objections by the transmission developer and independent power producer sectors, MISO management has reiterated its recommendation that $200 million in proposed out-of-cycle projects by Entergy be approved by the RTO.

“We continue to recommend approval by the board at the April meeting” of the six out-of-cycle projects, Jeffrey Webb, senior director of expansion planning, told the System Planning Committee of the Board of Directors on April 7.

The largest and most controversial of the out-of-cycle projects is $187 million in transmission improvements Entergy said are necessary to support a wave of new industrial development in the Lake Charles, La., region.

The committee took up the issue in March but stopped short of endorsing the Entergy projects despite a request to do so by Entergy Louisiana CEO Phillip May. (See MISO Board Questions Execs on Entergy Out-of-Cycle Requests.)

The full board has been invited to take part when the matter is discussed again by the committee on April 21. That is two days before the April 23 board meeting, when a final vote is expected.

MISO staff provided point-by-point rebuttals to written objections that dissenting sectors recently filed with the Planning Advisory Committee. The objections repeated complaints made earlier, challenging the certainty of Entergy’s load projections and questioning whether the projects were larger than needed to meet base reliability needs. They also alleged MISO failed to follow its Business Practices Manual, limiting opportunity for thorough stakeholder review.

In regard to the assertion that Entergy hasn’t provided sufficient evidence of underlying load projections, MISO staff insisted that nothing in the Tariff requires a load-serving entity to provide “verification and additional supporting documentation” for load projections.

MISO said Entergy’s growth projections are consistent with “widely publicized” projections of significant new industrial developments.

MISO’s Legal Obligations

System Planning Committee members inquired about MISO’s legal obligations in vetting out-of-cycle project requests. General Counsel Steve Kozey said MISO generally must make a good faith effort, but it is neither MISO’s nor the board’s role to litigate to a third party’s satisfaction.

Committee member Eugene Zeltmann pointed to comments filed by the Transmission Developer sector that suggested some transmission equipment included in the current out-of-cycle request was also part of a 2014 request, suggesting that it may be double-counted.

MISO staff replied that MISO staff did not double count that equipment and that it was distinct from earlier out-of-cycle projects.

Committee Chairman Michael Evans asked Webb to respond to concerns by some stakeholders that MISO did not provide adequate time for stakeholders to comment on the out-of-cycle requests.

Webb said an out-of-cycle request by its nature is necessarily “a compressed” time period but that staff abided by procedures.

Stakeholders Split

A stakeholder opposing the Entergy’s out-of-cycle requests was equally resolute.

“We continue to disagree with MISO staff,” said George Dawe of Duke-American Transmission Co., who represents the Competitive Transmission Developer sector.

He added that the process followed by the RTO “has called into question MISO’s credibility.”

But Lin Franks, senior strategist at Indianapolis Power & Light, countered that what Entergy has proposed is indeed a reliability project and that she doubted that board members wanted to be accused of causing delays leading to reliability problems.

“This is a reliability issue and not an economic one,” she said.

April 14, 2015

FERC Considering NIPSCO Proposals on PJM-MISO Seam

On Feb. 12, the Federal Energy Regulatory Commission asked for comments on the pros and cons of six potential rule changes intended to push PJM and MISO to create cross-border transmission projects (EL13-88). The changes were proposed by Northern Indiana Public Service Co. (NIPSCO) in December 2013.

The commission asked commenters to opine on the costs and technical feasibility of implementing requirements that MISO and PJM:

Run their cross-border transmission planning process concurrently with the RTOs’ regional transmission planning cycles, rather than after them.
Develop a single model that uses the same assumptions in the cross-border transmission planning process. Until the joint model is developed, the RTOs would be required to ensure consistency between their planning analyses and apply their reliability criteria and modeling assumptions consistently.
Use a common set of criteria in evaluating cross-border market efficiency projects.
Consider all known benefits, including avoidance of future market-to-market (M2M) payments made to reallocate short-term transmission capacity in real-time operations, when evaluating cross-border market efficiency projects.
Establish a process for joint planning and cost allocation of lower-voltage and lower-cost cross-border upgrades.
Amend their Joint Operating Agreement to improve the processes for new generator interconnections and generation retirements.

The commission also asked for comments on whether persistent M2M payments indicate the need for new transmission and on NIPSCO’s and others’ estimates of M2M payments. FERC also asked for examples of projects considered but not developed under the cross-border transmission planning process and the reasons why they were not completed.

April 14, 2015June 15, 2023

ISO-NE Proposes New Capacity Zones for FCA 10

By William Opalka

ISO-NE has proposed two new capacity zones for Forward Capacity Auction 10 next year (ER15-1462).

The petition filed with the Federal Energy Regulatory Commission on April 6 reflects where the RTO expects transmission constraints to be most severe in the 2019-2020 delivery year. ISO-NE requested that FERC approve the proposed zones by May 29, before the June 1 deadline for qualifying existing capacity and submission of de-list bids.

One new potential zone is Southeastern New England (SENE), a combination of the existing Northeastern Massachusetts/Boston zone with Southeastern Massachusetts/Rhode Island. The other new zone, Northern New England (NNE), is a combination of the existing Maine, New Hampshire and Vermont load zones.

ISO-NE said these are “potential” new capacity zones. “At this phase of the zonal development process, the appropriate boundaries are simply being defined so that if these capacity zones are needed, they can be modeled in the auction,” said Alan McBride, director of transmission strategy and services.

No changes are proposed with the current West-Central Massachusetts or Connecticut zones.

SENE is proposed as an import-constrained capacity zone, while NNE is proposed to be export-constrained.

For FCA 9 the zones were: NEMA/Boston, SEMA/RI, Connecticut and Rest-of-Pool, which includes West-Central Massachusetts, Vermont, Maine and New Hampshire.

The RTO conducts an annual assessment of transmission transfer capability to identify system weaknesses as part of its New England Regional System Plan. Modeling showed the effects of recent and pending plant closures, including the Vermont Yankee nuclear plant last year and the 2017 planned mothballing of the 1,535-MW Brayton Point generation station in Massachusetts.

Transmission upgrades planned for eastern Massachusetts will allow power to move more freely within the proposed zone, but constraints were found where the new, larger zone connects to the others. “These constraints are such that new, qualified resources located in either zone would be helpful in addressing the overall constraints. That is, new resources in SEMA/RI would be helpful in unloading the constraints,” according to the filing.

In FCA 9, SEMA/RI did not have enough capacity resources bid into the auction. (See Prices up One-Third in ISO-NE Capacity Auction.)

In NNE, power flow studies indicate an existing transmission interface is located along the southern borders of New Hampshire and Vermont and the northern border of Massachusetts. Without Vermont Yankee and Brayton Point, “the North-South flows are now forecast to be more concentrated along the lines connecting southeastern New Hampshire with eastern Massachusetts,” the RTO said.

The Connecticut zone was unchanged due to new resources that entered the zone in FCA 9. (See Exelon, LS Power Join CPV in Adding New England Capacity.)

April 14, 2015

Appeals Court Ratifies New York Capacity Zone

By William Opalka

A federal appeals court has rejected challenges to the Lower Hudson Valley Capacity Zone in New York (14-1786).

Utility companies and the New York Public Service Commission had appealed an August 2013 order by the Federal Energy Regulatory Commission creating the zone, saying it would lead to a windfall for power generators. (See New Yorkers Upset over NYISO Capacity Zone.)

A three-judge panel of the U.S. Second Circuit Court of Appeals ruled in favor of FERC on April 2 in a 61-page opinion.

“We conclude that FERC articulated sound economic principles supporting the creation of the Lower Hudson Valley Zone and satisfactorily explained how those principles justified its conclusion,” the court said.

The options for the losing parties are to ask for an en banc rehearing before the entire court or to directly petition the U.S. Supreme Court.

“We are disappointed, as the capacity zone has unfairly and artificially raised energy prices for homes and businesses in our service territory. We are reviewing the court’s decision, however our legal options are very limited as there are no reasonable or promising actions available to us,” said Central Hudson Gas & Electric spokesman John Maserjian.

Central Hudson says monthly bills have increased by 6% for residential customers and 10% for large industrials.

NYISO, in response to previous FERC orders, created the zone in the counties north of New York City in August 2013. The lawsuit challenging was filed after additional charges in the zone went into effect May 1, 2014.

NYISO and FERC maintained that generation resources were needed because price signals were insufficient to encourage power plant developers to site facilities there and that transmission constraints threatened reliability.

“We are not persuaded that there is anything unreasonable in FERC’s conclusion that higher prices were necessary to ensure reliability by generating accurate price signals in the long run,” the court wrote.

FERC said the congestion issue has been discussed since 2006 without a solution. Consumers have been shielded from higher prices since that time, it noted.

The companies and the PSC had argued that proposed transmission projects would relieve the constraints. (See Tx Plan to Open NY Choke Points Without New ROWs.) Another project would create a corridor from the Canadian border to New York City, making renewable energy generation from upstate more readily available.

The court sided with FERC’s contention that the projects have not yet been certified and that FERC “rationally explained its decision to act according to existing market conditions rather than speculative future conditions.”

April 14, 2015

Stakeholders Skeptical of PJM Proposal for ‘Historic’ Capacity Transfer Rights

By Suzanne Herel

VALLEY FORGE, Pa. — Stakeholders last week continued their debate over PJM’s proposal to create “historic” capacity transfer rights for some load-serving entities, with the Independent Market Monitor cautioning the Market Implementation Committee that the new Tariff language would constitute a “fundamental change.”

The proposal resulted from a problem statement approved by the MIC in December to review modeling practices that the RTO said may be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market.

The changes would allow market participants to use generation resources outside of their locational deliverability areas (LDA) to meet their internal resource requirements if that external capacity agreement was in place before June 1, 2007, when PJM implemented its Reliability Pricing Model. Previously, there was no locational differentiation made among capacity resources.

The proposal would address the situation faced by the Illinois Municipal Electric Agency, which last year won a federal waiver to allow it to use capacity resources outside of the Commonwealth Edison LDA to meet its internal resource requirement in serving its Naperville, Ill., load.

The Federal Energy Regulatory Commission granted IMEA a waiver for the 2017/18 delivery year after the ComEd LDA last year was modeled for the first time with a separate variable resource requirement curve (ER14-1681).

In January, however, the commission rejected IMEA’s request to continue use of the waiver for future delivery years, saying it had enough time to prepare to meet its internal resource requirement (ER14-1681-001). The commission also rejected a specific waiver request for the 2018/2019 delivery year (ER15-834). (See Illinois Regulators, IMM Line Up Against IMEA Capacity Waiver Request.)

PJM estimates 1,037 MW of historic external resources would qualify under its proposal: 122 MW in the DOM zone, 533 in COMED, 261 in AEP and 121 in DAY.

“This isn’t a piddling amount of megawatts,” GT Power Group’s Dave Pratzon said.

One stakeholder, who declined to be identified by name, said the rule change would be fair if it protects the property rights of load-serving entities that had funded transmission upgrades that increased the capacity emergency transfer limit (CETL) into their region.

But he said it may be “inequitable” if it also covers those whose only claim is a firm transmission reservation that predates RPM. Others observed the change would give such LSEs a preference over their neighbors for available transmission capacity.

Pratzon said he was concerned that PJM would be unable to set a “bright line” to distinguish between entities that have legitimate claims from those that don’t.

“It does seem to be creating a preferential set of rights for a certain group of people. I wouldn’t want us to set something up where in effect we’re giving people a second bite of the apple for certain decisions they made in RPM that they wish they hadn’t made,” he said. “I want to make sure we’re not putting ourselves on a slippery slope to other requests for special treatment.”

Mark Hanson, an economic analyst for the Illinois Commerce Commission, said the proposal goes too far. “It seems like maybe [entities such as IMEA have] gone from being too much at risk to being immunized from risk,” he said.

Market Monitor Joe Bowring said the change “represents a very substantial, fundamental change to the way [capacity transfer rights] are allocated within LDAs.”

Stu Bresler, PJM vice president of market operations, said the proposal would apply to a “well-defined subset” of LSEs. “It could never grow. We’d never have a new one,” he said.

Bresler said PJM will provide additional information on its proposal at next month’s MIC meeting.