The Federal Energy Regulatory Commission last week approved an uncontested settlement over the 2010 move by two Duke Energy subsidiaries from MISO into PJM (ER12-91).
FERC had rejected a February 2013 settlement over the move by Duke Energy Ohio and Duke Energy Kentucky, saying it unfairly imposed transition costs on customers that should be borne by the utilities.
The Duke companies agreed in the original settlement to reimburse American Municipal Power for any transition costs and 75% of “legacy” transmission expansion costs resulting from the move. The commission said that discriminated against other Duke customers that had not received exemptions from the transition and legacy costs, which Duke estimated at $518 million. (See FERC Rejects Settlements over ATSI, Duke Moves to PJM.)
FERC then set a hearing over how much Duke would pay to resolve its obligations for transmission expansion projects in MISO.
The new settlement, filed last October, was signed by the Duke companies and the members of AMP, Buckeye Power and East Kentucky Power Cooperative. Also signing on were the Indiana Municipal Power Agency, Dayton Power & Light, and Ohio municipalities Hamilton and Blanchester.
Under the settlement:
Effective Jan. 1, 2012, the Duke companies’ revenue requirement for wholesale transmission service provided in the DEOK Zone will not include any PJM transition costs or internal integration costs.
The Duke companies will not recover any MISO “legacy” transmission expansion costs in rates for transmission service provided since Jan. 1, 2012. Going forward, Duke will be permitted to recover 30% of MISO legacy costs.
The Duke companies’ return on equity for wholesale transmission service shall be reduced to 11.38%, including a 0.5% adder for participation in an RTO. Duke and the other signatories agreed not to seek FERC approval for a change in the ROE that would be effective before June 1, 2017.
FERC granted a request for rehearing made by the RTO, which said that gaining consensus from stakeholders would be difficult in such a tight schedule. It also argued that prematurely “overlaying” market-based solutions could create other problems and not be cost-effective. (See ISO-NE: Reverse Market-Solution Order.)
“Noting ISO-NE’s observation that a winter reliability solution may be necessary for the next several winters, we find that an expanded version of the current winter program might better produce the desired results in terms of reliability than the introduction, at this point in time, of the market-based solutions examined by ISO-NE,” FERC wrote.
While agreeing to grant the request, Commissioner Tony Clark expressed “frustration given ISO-NE’s inability or reluctance” to develop a program. “I vote in favor of today’s order as a matter of pragmatism given the practical challenges ISO New England asserts in its filing,” he wrote in a concurring opinion.
The New England Power Generators Association had argued that the region shouldn’t wait until 2018 — when the RTO’s pay-for-performance program takes effect — for a market-based solution. (See ISO-NE in Precarious Position for Winter.)
“We are disappointed,” NEPGA President Dan Dolan said. “But we are encouraged that FERC used some rather strong language, particularly Commissioner Clark, to try to put some mechanism in place, rather than just a series of one-off programs.”
ISO-NE has used out-of-market programs for the past two winters to maintain reliability.
FERC prodded ISO-NE to continue work on a market-based program, even with this reprieve. “The commission expects ISO-NE to abide by its commitment to work with stakeholders to expand any future out-of-market winter reliability program to include ‘all resources that can supply the region with fuel assurance,’ such as nuclear, coal and hydro resources,” it said.
NEPGA has complained that the winter reliability program should be resource-neutral. However, in both years of its existence, the program has relied on oil and natural gas.
WASHINGTON — Federal Energy Regulatory Commission Chairman Norman Bay named Larry Gasteiger as his chief of staff and Larry Parkinson as the director of the commission’s Office of Enforcement. Bay made the announcement at his first open meeting as FERC chairman on Thursday.
Gasteiger served as deputy director under Bay when the latter headed Enforcement, and he has been serving as acting director since Bay was confirmed as a commissioner in August. Before joining Enforcement, Gasteiger was the director of the Division of Tariffs and Market Development – East in the Office of Energy Market Regulation. He also served as a deputy associate general counsel, and legal advisor to former Chairman Joseph T. Kelliher after joining FERC in 1997 from the Commodity Futures Trading Commission.
Parkinson had served as director of Enforcement’s Division of Investigations since March 2010. Before joining the commission, Parkinson held stints as deputy assistant secretary at the U.S. Department of the Interior, general counsel of the FBI and U.S. Small Business Administration, and assistant U.S. Attorney for D.C.
TULSA, Okla. — SPP’s Markets & Operations Policy Committee last week approved new rules on how mitigated offers will be calculated for generators that fail market power tests, choosing a solution that includes default values for variable operation and maintenance (VOM) costs.
It was the second time the group had approved new rules on mitigated offers. In December, the SPP Board of Directors rejected a proposal that had been approved by MOPC over the objections of the Market Monitoring Unit, saying it wanted a solution that had broader support.
The new proposal, which passed on a voice vote, did not win the MMU’s endorsement, however.
MMU Director Alan McQueen told MOPC that the revised proposal’s use of default VOM values was an improvement because it reduced ambiguity. He also praised the inclusion of an adder for frequently mitigated resources.
Too ‘Generic’
But he said he was concerned that the proposal “removes any reference to competitive levels,” replacing it with “variable O&M,” a term he said is too “generic” because it could refer to costs incurred over a decade. That does not conform to the Federal Energy Regulatory Commission’s mitigation premise that offers are “approximately equal to short-run marginal cost,” he said.
“It actually adds ambiguity back into the overall process that the Market Monitor is going to have to use,” he said.
McQueen said this would cause problems both when the MMU is reviewing offers from units that claim costs higher than those in the default schedule and when it and stakeholders conduct their annual review of the default levels.
SPP rules allow units found to have market power to submit market offers of up to 125% of the mitigated energy offer, which would be based in part on the VOM defaults. Thus a combined-cycle plant with a heat rate of 10 MMBtu/MWH that would be paid $41/MWh, including $6 in VOM based on the default table, could receive as much as $51.25/MWh, with an implied VOM of $16.
The ‘Next Enron’
“When is the next Enron going to be entering the SPP market?” McQueen asked. “Do you want them to be deciding what should be included in the reference level or do you want the Market Monitor, who’s listening to everybody who’s in the market?”
McQueen said that based on his discussions with generators, he believed 80% of them supported use of the defaults.
Richard Ross of American Electric Power disagreed. “I can add up fairly easily enough megawatts [opposing defaults] to figure out that it isn’t 80%.”
Nevertheless, Ross said AEP would support the new rules.
Jake Langthorn of Oklahoma Gas & Electric said he was disappointed that the default solution did not include compensation for maintenance obligations under long-term service agreements. “If the LTSAs were included, we wouldn’t have a beef with it,” he said.
Staff Supports
Although the solution did not have the unqualified support of members and the MMU, SPP Chief Operating Officer Carl Monroe said RTO staff supported the proposal because it resolved some of the longstanding disputes over VOM calculations.
Richard Dillon, SPP’s director of market design, noted that FERC’s recent State of the Markets report found the RTO’s day-ahead on-peak power price to be the second-lowest in the country last year at $40/MWh, higher than only the $39 at the Mid-Columbia pricing hub in the Pacific Northwest.
“That is a good indicator that even at 125% [of the mitigated offer] the competitive price is under market,” Dillon said.
“Columbia is all hydro. Being only behind a hydro system is a problem.”
TULSA, Okla. — SPP staff’s recommendation that the RTO approve a 21-mile 115-kV line from Walkemeyer to North Liberal as part of a reliability solution in southwestern Kansas failed to win stakeholder endorsement last week.
Staff’s solution received almost 64% support from the Markets & Operations Policy Committee, falling short of the two-thirds needed to recommend it to the SPP board.
Staff considered three alternatives, two of which would have delayed the line indefinitely, instead relying on operating guides for Sunflower Electric Power’s 76-MW Cimarron River Station to provide relief from thermal or voltage violations.
Option 1 would add a new substation with a 345/115-kV transformer on the Hitchland–Finney 345-kV line and a new 1-mile 115 kV line from the substation to Walkemeyer at an estimated cost of $17.8 million. Cimarron would be dispatched for up to 58 MW when needed to avoid violations.
Staff’s suggestion, option 2, included the new substation and transformer but would add the Walkemeyer-North Liberal line for an additional $17.5 million, avoiding the need to rely on Cimarron for reliability.
Although option 2 had higher upfront costs, staff said it was about $1.4 million cheaper than option 1 on a net present value basis over 20 years ($68.9 million vs. $67.5 million).
Option 3, which would have relied solely on the Cimarron plant, had an NPV of $84 million and only “marginally” solved voltage violations, staff said.
Tom Hesterman of Sunflower said option 1 was the best choice, being a “statistical tie” with option 2 in NPV and having lower upfront costs.
Brian Gedrich of NextEra supported the 21-mile addition, saying “it could be the only competitive project” SPP approves in the current planning cycle.
The Cimarron plant has two natural gas-fired units: a 61-MW unit built in 1963 and a simple-cycle 15.5-MW combustion turbine added in 1967.
American Electric Power’s Richard Ross was skeptical of reliance on the aging plant, saying Sunflower was not obligated to keep it running if it requires costly repairs. He said he feared the unit could fail, necessitating the Walkemeyer-North Liberal project — but without the lead time necessary to open it to competitive bidding.
Sunflower’s Al Tamimi said the company invested heavily in the unit — adding a new cooling tower in 2014 — and had no plans to retire it. Southwestern Public Service’s phase shifter can maintain system reliability if the Cimarron plant is unavailable, Tamimi added.
“I just don’t think it’s appropriate for us to continue to rely on a unit we can’t rely on,” Ross insisted.
“That’s your opinion,” Tamimi responded. “You don’t know anything about the unit.”
“I do know that if the unit fails tomorrow and you don’t return it to service that … you’re going to turn around next year and put it right in the model as unavailable and the project … that we’re talking about here” will be required, Ross fired back. “And the difference will be whether or not you’ve pushed things out to where it’s not a competitive project.”
Antoine Lucas, director of planning, said staff would consider stakeholders’ comments before making its recommendation to the board.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:20)
Members will be asked to endorse the following manual change:
A. Manual 14D: Generator Operational Requirements — Changes made to comply with a recent advisory from the North American Electric Reliability Corp. on generator governor frequency response.
3. ENERGY MARKET UPLIFT SENIOR TASK FORCE (9:20-9:40)
Members will be asked to approve revisions to rules developed by the Energy Market Uplift Senior Task Force regarding treatment of combustion turbine lost opportunity costs. Under the proposal, units with start-up and notification times of no more than two hours and minimum run times of two hours would be paid lost opportunity costs if they are not dispatched. Resources with real-time start-up and notification times or minimum run times of more than two hours will not receive lost opportunity payments unless PJM bars them from running in real time to avoid transmission overloads.
SPP said its integrated marketplace resulted in production cost savings in each of the last 12 months. (See “PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs” in Operating Committee Briefs, April 14.)
4. RESIDENTIAL DR MEASUREMENT AND VERIFICATION (9:40-9:50)
Members will be asked to approve Tariff and manual revisions regarding residential demand response measurement and verification, which PJM plans to file in late April. The changes, endorsed at the Jan. 22 Members Committee meeting, have been updated to include an additional delivery year. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25.)
5. TARIFF HARMONIZATION SENIOR TASK FORCE (9:50-10)
Members will be asked to endorse a problem statement and issue charge by Calpine seeking to allow more flexible market offers for physical generating resources. PJM is the only U.S. RTO that does not allow generators to vary their cost- or market-based offers hourly. This problem statement would consider allowing generators to revise their offers hourly to reflect changes in gas prices. (See PJM May Consider Hourly Pricing for Generators.)
7. REGIONAL PLANNING PROCESS SENIOR TASK FORCE (10:15-10:25)
On first reading, members will be asked to approve a recommendation directing the Planning Committee to develop guidelines for considering generation interconnection projects as drivers under the multi-driver transmission project approach. The committee also will be asked to place the task force on hiatus, available to be returned to operation if needed based on future rulings by the Federal Energy Regulatory Commission.
Members Committee
CONSENT AGENDA (12:05-12:10)
B. Members will be asked to approve proposed minor “non-substantial” provisions regarding financial transmission rights’ auction clearing deadlines and trading periods.
The Federal Energy Regulatory Commission on Thursday rejected tariff revisions submitted by New England Power, saying they would allow the company to exceed the commission’s limits on transmission returns on equity (ER15-418).
In Opinion 531, FERC last year ordered that the New England Transmission Owners’ total ROE, including base rate and incentives, could not exceed 11.74%, the top of the “zone of reasonableness.” (See FERC Splits over ROE.)
As a result, New England Power was required to revise the tariff governing the transmission facilities of its affiliates, Massachusetts Electric and Narragansett Electric, which it operates as a single integrated system.
But FERC ruled that the revisions the company filed would have improperly allowed it to earn returns of more than 11.74% on some of its assets as long as the average ROE was below the cap.
The commission said the company’s language “relies on the same interpretation of the term ‘total ROE’ that the New England Transmission Owners presented on rehearing in the Opinion No. 531 proceeding. The commission rejected that interpretation in Opinion No. 531-B, and we do so here for the same reasons.”
The commission also ordered the use of data from calendar year 2013, rather than 2012, to calculate the estimated decrease in revenues resulting from New England Power’s tariff revisions. The company had calculated a $2.2 million rate decrease if 2012 was used as the test year, and nearly a $2.3 million decrease based on data for 2013.
SPP said its integrated marketplace produced net savings of about $210 million in the first year after combining 16 balancing authorities into the marketplace.
Over the rolling 12-month period ending in March, the market produced gross benefits of $430 million, or $210 million after accounting for $170 million in historical savings and $50 million in annual cost. That analysis excludes March 2013, the first month of the transition, when the RTO operated with higher unit commitments than required.
SPP-MISO Market-to-Market Showing Results
SPP’s market-to-market initiative with MISO, which began last month, is paying dividends, SPP’s Bruce Rew told members. Rew said there was activity on all but two days in March, with daily settlements ranging from $2,000 to more than $1 million.
Rew said the two RTOs are working to address “oscillation” at some locations, where congestion returns almost immediately after being relieved.
“It’s working,” he said. “It needs some improvements and we’re working closely with MISO to do that.”
Proposal on Disqualifying Regulation Resources Remanded
The Markets & Operations Policy Committee remanded Revision Request 33 to the Market Working Group. The request would allow SPP to disqualify resources from participation in the regulation market for poor performance.
Bill Grant of Southwest Public Service Co. said he was concerned that the rule was overly strict and that its requirement that resources respond within four seconds would result in the unnecessary disqualification of many resources.
“You’re already financially incented to respond. So we’re questioning the need for disqualification altogether,” he said. “… If we’re going to start disqualifying people over four-second deployments, people need to understand that because most people’s [energy management system] might not respond in four seconds.”
Staff said SPP’s intent is to improve the response of the poorest-performing “outliers.” Staffers said they have never disqualified a resource.
Members approved RR44 and RR45, which add details on how SPP calculates regulation resources’ actual mileage for settlement purposes.
Members OK Short-Term Unit Commitment Study
Members approved RR49, which would create a short-term reliability unit commitment (RUC) study as part of the intra-day RUC process. The study will provide results for 15-minute intervals, allowing operators to make unit commitments with more granularity than the current one-hour study. It is expected to reduce the number of real-time manual commitments.
Delays on Z2 Credit Fix Spark Frustration
Members expressed frustration with SPP’s slow progress in creating a process for properly crediting and billing transmission customers for system upgrades under Tariff attachment Z2. Repeated delays in the project led SPP to reorganize the staff team handling it. SPP’s software vendor is now projecting completion of the project by June 2016.
The project has proven more complex than originally expected because of the need to avoid over-compensating project sponsors, and to include a way to “claw back” revenues from members who owe SPP money for other reasons. Accounting for transfers of reservations has also proven a challenge.
“I have been dealing with this issue for so many years,” said Steve Gaw, representing The Wind Coalition. “I don’t know how many years ago we were being told that it would be fixed ‘next quarter.’
“I don’t have any more faith in the dates,” he continued. “I just don’t know when there’s going to be accountability [to the] folks who have been owed money for all of this time.”
Monroe acknowledged the frustration. “We’re playing with the hand we’ve been dealt,” he said.
2016 ITPNT Scope Approved
MOPC approved the scope of the 2016 Integrated Transmission Planning Near-Term (ITPNT), including the automatic recommendation of the notices to construct from the Consolidated Balancing Authority scenario.
The 2016 ITPNT’s primary focus is to identify solutions required to address potential reliability problems under normal conditions (no contingency) and (N-1) scenarios. It will include modeling of the system through 2020.
It will also reflect improved dispatch of wind resources and include the Integrated System — the Western Area Power Administration Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District — as SPP members. (See Spurned by Entergy, SPP Expands in Great Plains.)
Keystone Pipeline Would Add SPP Loads
The controversial Keystone XL pipeline would add at least 400 MW of load to SPP based on its use of about 20 pumping stations at 20 to 25 MW each, said Jay Caspary, SPP director of research, development and special studies.
Caspary said those loads, in addition to unserved loads in New Mexico and Kansas, helped justify the Notices to Construct that SPP has issued.
Bary Warren of Empire District Electric said SPP should be wary of overestimating loads, saying that gas and oil producers have recently announced 30 to 50% cuts in capital spending due to falling oil prices.
“The projects are probably needed,” he said. “The question is when are they needed? Should they be competitively bid? … At what voltage?”
Charters Approved
The committee approved the charter of the newly formed Stakeholder Prioritization Task Force and approved a revised charter for the Transmission Planning Improvement Task Force with no substantive changes.
MOPC also approved a change in the charter of the Transmission Working Group, allowing an increase in its membership from 20 to 24. Two of the seats will be assigned to representatives of WAPA-UGP and Basin Electric. Existing SPP members will be able to apply for one of the additional two seats on the working group.
Chief Operating Officer Carl Monroe said other committees may see similar increases in their membership to accommodate the new members.
The new charter also updates the group’s scope to include:
Changes to the SPP portion of North American Electric Reliability Corp. flowgates;
Reviewing and developing rating criteria, including minimum design standards;
Reviewing and approving study information for interconnections; and
Reviewing technical and reliability aspects of all policies, business practices, study scopes, SPP criteria changes and tariff changes.
Regional Allocation Review Delayed
Members approved delaying the regional cost allocation review until new models are developed for the 2017 Integrated Transmission Plan 10-Year Assessment. This would delay completion of the RCAR II analysis until July 2016.
Members were concerned with proceeding with the models being used in the 2015 ITP10, which are about two years old and do not include Kansas City Power and Light’s January decision to stop burning coal at its Montrose power plant in Clinton. The company plans to close or convert one of its units to natural gas by 2016 and make similar decisions on the remaining two units by 2021.
SPP, which completed its last cost allocation review in 2013, is required to conduct such reviews every three years.
The Federal Energy Regulatory Commission last week denied a request by Virginia Electric and Power Co. to terminate its obligation to purchase electricity from nine North Carolina solar facilities. The facilities, owned by Community Energy Solar, each have a net capacity of 4.99 MW.
VEPCO had filed the request last October.
In 2008, FERC terminated VEPCO’s obligation to purchase energy from qualifying facilities (QFs) larger than 20 MW in its service territory, with the presumption that such facilities have nondiscriminatory access to the PJM markets.
At the same time, FERC created the presumption that smaller qualifying facilities did not have the same access to the markets because of their size. The commission placed the burden of proof on utilities seeking to terminate agreements to show otherwise.
“We find that the nine Community Energy QFs established legally enforceable obligations under [the Public Utilities Regulatory Policies Act] prior to VEPCO’s filing of its application to terminate its mandatory purchase obligation for those QFs, and we therefore deny VEPCO’s application,” FERC said in its April 16 ruling (QM15-1-000).
The Federal Energy Regulatory Commission on Thursday clarified unresolved issues from a previous order on the installed capacity market in New York that have been pending for nearly three years (EL11-42).
In it, FERC accepted NYISO’s filings in response to the June 22, 2012, order, which directed the ISO to clarify how the mitigation exemption test and offer floor calculations are implemented. The commission had found merit in a complaint by NRG Energy and several other generators that NYISO’s implementation of the buyer-side mitigation rules lacked transparency.
NYISO said the 2012 order was unclear with respect to the comparison made between the default offer floor and unit net cost of new entry in determining the offer floor. FERC said NYISO’s interpretation is correct, in that the value for unit net CONE to be used should be only the first-year value of the three-year average of annual unit net CONE.
FERC also:
Confirmed NYISO’s method of adjusting the offer floor for inflation.
Ordered NYISO to change how it adjusts unit net CONE for inflation.
Affirmed its finding that NYISO has justified its use of natural gas futures prices and historical prices in its net CONE calculations.
Ordered NYISO to incorporate language allowing the Market Monitoring Unit to consider all factors relevant to mitigation exemption and offer floor determinations in its reports reviewing whether the ISO’s mitigation and exemption determinations were conducted in accordance with its Market Administration and Control Area Services Tariff.
FERC also ruled Thursday in a case related to the ICAP, in which Astoria Generating and TC Ravenswood had alleged that NYISO’s buyer-side market mitigation provisions were improperly administered (EL11-50). The order generally denied rehearing, but it ordered the ISO to use the Astoria II plant’s actual cost of capital in its mitigation exemption determination.
