TULSA, Okla. — SPP members last week rejected a request from Western Farmers Electric Cooperative for a waiver from a rule barring base plan transmission funding for wind generation projects that push wind’s share of capacity above 20% of summer peak load.
Members of the Markets & Operations Policy Committee agreed with a staff recommendation, which found that Western Farmers’ plan to add 100 MW of wind generation did not qualify for the waiver.
At the same time, members agreed that the 20% threshold — set years ago when SPP was comprised of smaller balancing authorities and there was concern over being able to balance large swings in wind generation — should be revisited now that is operating a vast area as a single balancing authority.
“I think some of the concerns about the operational challenges don’t exist or the limit could be higher,” said Antoine Lucas, director of planning. “But until there’s a new standard, we need to follow the 20%.”
Steve Gaw, representing The Wind Coalition, said the justification MISO presented to the Federal Energy Regulatory Commission for the limit was “entirely about reliability.” Continuing the 20% limit now, he said, is “hard to justify.”
Mitchell Williams, representing Western Farmers, said the cooperative needs to add more baseload generation because it may turn its one baseload coal plant into a peaking unit under the Environmental Protection Agency’s Clean Power Plan. The 100 MW from the Balko wind project — which the cooperative said was the most competitive resource available — would push wind from 19% to 25% of Western Farmers’ peak load over the next decade.
“We don’t think [the base plan funding] is a lot of money, but it’s still money and I would not be responsible to my board if I didn’t ask,” Williams said.
American Electric Power’s Richard Ross was unsympathetic. He suggested Western Farmers should have used the SPP screening study process so it could have considered the transmission costs before agreeing to purchase the wind capacity.
Although the waiver request won only 33% support, there appeared to be consensus among members on the need to revisit the limit as more wind is expected to be added under the EPA rules.
“This is not going away,” said Bill Grant of Southwestern Public Service. “It’s coming at us like a freight train.”
The Obama administration has received more than 100 pages of letters from Native Americans calling for a rejection of the proposed $8 billion Keystone XL Pipeline, claiming that the project would infringe on their water rights and damage sacred land, according to The Hill. The news service sought the letters through Freedom of Information Act requests with the Department of the Interior and found they were nearly unanimous in opposition of the project. The letters arrived just before the department is scheduled to file its own comments with the State Department on the pipeline. The Oglala Sioux Tribe wrote that it “continues to fully and completely oppose” the pipeline, as did the Northern Arapaho Tribe, the Ponca Tribe of Nebraska, the Blackfeet Tribe and the Yankton Sioux Tribe.
TransCanada, the company behind the project, said it has worked with the tribes, changed plans to address their concerns, and spent thousands of hours meeting with them. “We share a deep respect for the land and we deal with the concerns expressed by tribes and other landowners respectfully,” a company spokesman said. The final decision will come from the State Department.
Judges Appear Skeptical of Challenge to EPA Air Rules
A panel of judges of the D.C. Circuit Court of Appeals heard arguments from a platoon of attorneys arguing that the Environmental Protection Agency’s Clean Power Plan is already costing states money and if upheld could lead to the closing of hundreds of coal plants.
But the questions from the judges, especially Thomas Griffith and Brett Kavanaugh, seemed aimed less at the effect of the Clean Power Plan than on the plaintiff’s strategy to attack the plan in court, even before the rules are finalized.
“Do you know of any case in which we’ve halted a proposed rule-making?” Griffith asked. “Why in the world would we resort to extraordinary writ, which we’ve never used before?
“It’s a proposed rule,” Griffith went on. “We could guess what the final rule will be. But we’re not in the business of guessing. We typically wait to see what the final rule will be.”
Fourteen states and two of the country’s largest coal companies are challenging the rule, which requires states to come up with plans to meet emissions reduction goals. However, EPA has already indicated that they could revise the rules based upon feedback from the states.
“For us to get in the middle of it before it happens seems highly unusual,” Kavanaugh said.
“While we have always said that it is unusual to set aside a proposed rule, we believe that it is legally justified and appropriate in this case,” said West Virginia Attorney General Patrick Morrisey after the hearing. “The EPA has made clear that it plans to finalize this rule and regulate based upon a section of the Clean Air Act where it lacks legal authority to do so.”
NRC Begins Special Inspection of Calvert Cliffs Plant After SCRAMS
The Nuclear Regulatory Commission has sent a special team of investigators to Exelon’s Calvert Cliffs nuclear station to determine why both units tripped offline during the April 7 transmission line failure that resulted in regional power failures. On that day, the failure of a transmission line in Southern Maryland caused both units at the 1,700-MW site to trip offline as designed. However, the diesel backup generator at one of the units failed after 11 seconds. It was the second time in five years that a diesel backup generator failed.
A report of the team’s inspection will be provided in 45 days.
EPA 2013 Greenhouse Gas Report Shows 2% Increase in a Year
U.S. power plants continue to be the largest emitters of greenhouse gas, accounting for 31% of all emissions in 2013, according to the Environmental Protection Agency’s 20th Inventory of U.S. Greenhouse Gas Emissions and Sinks. The report showed a 2% increase in emissions from 2012 to 2013, but a 9% drop since 2005. The agency said the rise was due to increased energy use across all sectors as well as a greater use of coal for generation overall in that period (see “Coal-fired Generation to Keep Rising” below). The agency is providing the full report, along with tools to work with the data.
Coal-fired Generation to Keep Rising Through 2025, EIA Says
The U.S. Energy Information Administration says electricity produced by existing coal-fired stations will increase from 2012 through 2025, according to its Annual Energy Outlook 2015. Using different economic scenarios, the report predicts energy production and usage. It indicates that while coal’s share of generation will fall from 39% in the U.S. to 34% in 2040, it will remain the largest share of total U.S. generation. The report shows renewable generation exhibiting the largest uptick, ranging from 50 to 121%, depending on the scenario. Construction costs continue to keep nuclear’s share from rising much, according to the predictions.
Shale Oil Boom May Be Over, Energy Information Admin Says
The oil output from seven of the country’s most productive shale formations is declining, the first indication that the oil shale boom may be over, according to the U.S. Energy Information Administration. The agency said production from the Bakken Eagle Ford, Haynesville, Marcellus, Niobrar, Permian and Utica formations will show a dip in production in May compared to April figures. April output for all seven regions was to be 5.62 billion barrels per day. Projected May output was tagged at 5.56 billion barrels, according to the Drilling Productivity Report.
The report already has some analysts putting on their doom-and-gloom glasses.
“We’re going off an inevitable cliff” because of the shrinking rig counts, Carl Larry, head of oil and gas for Frost & Sullivan, told Bloomberg News. The number of rigs in production, 802, is the lowest since March 2011. “The question is how fast the decline is going to go. If it’s fast, if it’s steep, there could be a big jump in the market.”
House Bill Gives States Right to Regulate Coal Ash
The House Energy and Commerce Committee has approved a bill that would allow states to largely bypass a recent Environmental Protection Agency rule on the storage and disposal of ash from coal-fired power plants. The EPA rule, promulgated last year, stopped short of declaring coal ash a hazardous substance and set rules for storage and disposal, but largely left it up to the states to enforce the rules.
The bill, introduced by Rep. David McKinley (R-W.Va.), would set up a coal ash permit system to be administered by states, Enforcement in states that do not institute a permit system would revert to EPA. McKinley said EPA left open the possibility that coal ash would be designated hazardous and that his bill would provide regulatory certainty for those tasked with overseeing coal ash storage and disposal.
“The science has been determined — coal ash is not a hazardous material,” he said. “But as a result of this administration’s executive actions, we have uncertainty” for more than 300,000 workers employed by industries that use coal for beneficial uses and other recyclers.
The Department of Energy is paying more than $5 million in scholarships and fellowships to 91 college students studying in nuclear energy fields. Since 2009, the department has given $25 million in scholarships to more than 500 students. The office said the scholarships are part of the Obama administration’s effort to support clean energy innovation. “By helping promote cutting-edge nuclear science and engineering,” Secretary Ernest Moniz said, “the department is helping advance American leadership in the safe, secure and efficient use of nuclear energy here and around the world.”
CARMEL, Ind. — Stinging from objections to Entergy’s proposed Lake Charles transmission upgrade, MISO has launched discussions that could lead to refinements in its procedures for handling out-of-cycle requests.
The procedural review was initiated after transmission developers and independent power producers objected to staff recommendations that the MISO Board of Directors approve Entergy’s six out-of-cycle requests. The largest and most controversial request is a $187 million transmission upgrade that it says is needed to support new industrial development around Lake Charles, La. (See MISO Staff Hold Firm on Entergy Out-of-Cycle Request.)
The MISO board could vote on the requests Thursday.
“We really want you guys to dig in and really tell us how you believe things should be,” Matthew Tackett, a MISO principal advisor, told the Planning Advisory Committee on Wednesday.
Stakeholders have challenged Entergy’s load projections and questioned its assertion that the projects were needed to meet base reliability needs. They’ve also alleged that MISO failed to follow its Business Practices Manual and that it provided only limited opportunity for stakeholder review.
Entergy said the need to serve additional industrial load wasn’t realized until after the conclusion of the annual MISO Transmission Expansion Plan (MTEP) process. MISO officials said Entergy’s out-of-cycle request was consistent with publicly announced industrial plant expansions and economic growth data for Lake Charles. MISO said Entergy has not shared some specifics about the projected new load growth, citing customer confidentiality.
Ambiguities?
One issue rising out of the Entergy request is tariff language that states that an out-of-cycle project review must be driven by “urgent” needs that require an expedited review.
MISO’s Business Practices Manual states that such out-of-cycle projects have a need date within three years and an expected in-service date within four years of an OOC project submission. George Dawe of Duke-American Transmission Co., who represents the Transmission Developers sector, sought a rationale for the difference between need date and in-service date.
“I agree that the language as written could use some improvement,” Tackett said.
The term “urgent” could “be a little bit ambiguous,” said Tia Elliott, director of regulatory affairs at NRG Energy.
Tackett said the review ultimately comes down to striking a balance between adequate stakeholder vetting and successfully addressing the need “in a timely manner.”
Dawe has complained that MISO’s review of Entergy’s request seemed rushed and predestined for approval.
Tackett stressed that the out-of-cycle approval process is designed for special circumstances, not for long-term projects that ordinarily would be reviewed within MTEP.
He also said MISO has limited authority to override or invalidate a distribution company’s load forecasts. He noted, however, that load modifications often have to be reviewed by state utility regulators.
Steve Leovy, a transmission engineer at WPPI Energy, suggested MISO could perform studies during the MTEP process that anticipate and model future expansions so that it could be better prepared for significant demand-forecast changes.
Tackett invited stakeholders to offer comments and to provide redlined versions of the Business Practices Manual by May 15.
A summary of comments and suggestions will be presented at the June Planning Advisory Committee meeting.
The Federal Energy Regulatory Commission on Thursday issued new reliability standards, denied rehearing on business practices and communication protocols and ordered a new format for electronic filing of required reports. The commission also outlined a plan for measuring the effectiveness of its initiatives to spur transmission spending.
Transmission Investment Metrics
FERC said it will begin collecting data on six transmission metrics in an effort to measure the effectiveness of Order 1000 and other transmission initiatives (AD15-12).
The metrics are intended to measure levels of transmission infrastructure by region and permit analysis of the impact of commission transmission policies.
They include two measures of persistent congestion, which FERC said would provide an indication of whether regions have invested enough in transmission to ensure reliability and reduce costs:
Annual number of Transmission Loading Relief (TLR) or unscheduled flow events, normalized based on retail load. This metric would apply in bilateral markets.
Persistence, in years, of price differentials between RTO/ISO market nodes and market-to-market flowgates. LMPs, forward capacity prices and trading hub prices will be used.
To gauge the impact of policy changes, three other metrics will measure relative transmission investment and the cost-effectiveness of that spending:
Circuit-miles of transmission added to the grid, normalized by retail load. Population density and other factors may need to be considered in using the metric to compare regions.
Load-weighted transmission investment, defined as the amount spent on new capital additions in a given year, weighted by retail load. Population density must be considered in comparisons.
Circuit-miles per dollar of investment, defined as the number of circuit-miles added in a year, divided by the total invested — a measure of cost effectiveness.
The final metric will attempt to measure the impact of Order 1000, which sought to open transmission development to competition. It would divide the number of bids or proposals from non-incumbents in a region by the total number of bids and proposals annually.
“This is important work that you’re doing,” Chairman Norman Bay told Ben Foster, an Office of Energy Policy and Innovation staff member who presented the metrics study to the commission. “The metrics presented by staff today will allow the commission and its staff to better see what works and what needs further improvement.”
FERC staff will consider whether to add more metrics as it gains experience with the initial six.
“This is an initial feasibility study,” Foster said in response to a question from Commissioner Philip Moeller on a timeline for further developments. “We’ve done an initial pass, but we want to look more deeply into it to see if in fact it will yield meaningful insights. So we don’t have a particular timeline for releasing any kind of analysis at this point.”
FERC spokeswoman Mary O’Driscoll said the effort will not impose any additional reporting requirements on RTOs or others, at least not immediately.
“This is the very beginning of the process,” she said. “If [FERC staff] need additional data they will seek it out at the time. For now, it’s all public data.”
Commissioner Cheryl LaFleur asked Foster if there was anything RTOs could do to help FERC get meaningful data.
Foster replied that staff is attempting to rely on publicly available data. “But we may well have questions, and if the people who compile that data would be open to helping to walk us through [it] … that would be the most helpful to us at this point,” he said.
Electronic Filing Protocols for Commission Forms
Electric utilities and others will be required to file FERC reports in XML (Extensible MarkUp Language), a replacement for the current software, Visual FoxPro, which is no longer supported by its developer, Microsoft.
Affected are four forms used by electric utilities:
Form 1: Annual Report of Major Electric Utilities, Licensees, and Others;
Form 1F: Annual Report of Nonmajor Public Utilities and Licensees;
Form 3Q: Quarterly Financial Report of Electric Utilities, Licensees, and Natural Gas Companies; and
Form 714: Annual Electric Balancing Authority Area and Planning Area Report.
Forms for natural gas companies and oil pipelines also are affected by the change (AD15-11).
Standards for Business Practices and Communication Protocols for Public Utilities
FERC denied a request by the Edison Electric Institute for rehearing of Order 676-H, which specified business practices and communication protocols for electric utilities. The order addressed redirect policies and included a requirement that transmission providers post on their Open Access Same-time Information Site (OASIS) explanations on their calculation of available transmission capacity (ATC) within one day (RM05-5-024). Compliance is required effective May 15.
Reliability Standards
The commission gave final approval to the following reliability standards developed by the North American Electric Reliability Corp.:
COM-001-2 (Communications) and COM-002-4 (Operating Personnel Communications Protocols). The rules require adoption of predefined communication protocols, including use of three-part communications, and an annual assessment of them. The commission ordered NERC to modify COM-001-2 to address internal communications that could have an impact on reliability (RM14-13).
BAL-001-2 (Real Power Balancing Control Performance) and four new definitions. The standard is intended to ensure that the grid maintains consistent system frequency. It adds a frequency component to the measurement of a Balancing Authority’s area control error (ACE). The commission ordered NERC to submit an informational filing on the potential impact of the standard and to revise one definition (RM14-10).
The commission also gave preliminary approval to, and invited comment on, two Notices of Proposed Rulemaking:
PRC-005-4 (Protection System, Automatic Reclosing and Sudden Pressure Relaying Maintenance), which requires testing and maintenance of certain sudden pressure relays. The commission said it plans a new definition and four revised definitions in the proposed standard (RM15-9).
PRC-002-2 (Disturbance Monitoring and Reporting Requirements), designed to ensure the availability of adequate data to allow analysis of bulk electric system disturbances (RM15-4).
Tech Conference on Reliability of Bulk Power System
FERC will hold its annual technical conference on the reliability of the bulk-power system on June 4 (AD15-7). The conference, which will be held at FERC headquarters, will be webcast. FERC said a detailed agenda will be issued later.
WASHINGTON — The Federal Energy Regulatory Commission completed a bloodless transition Thursday as newcomer Norman Bay replaced five-year veteran Cheryl LaFleur as chairman in a meeting marked by the usual cordiality — and disruptive protesters.
Bay, who was appointed commissioner last August, officially assumed the chair on Wednesday from LaFleur, who had served as head of the panel since the November 2013 resignation of Jon Wellinghoff.
At the beginning of Thursday’s meeting, Bay presented LaFleur with two gifts: a framed letter from the New England Patriots thanking her for her service as chairman and a FERC jersey, which Bay said he hoped she would wear at every open meeting. A diehard Boston sports fan, LaFleur often wears her teams’ jerseys when they are in the playoffs.
After some affable remarks on LaFleur’s tenure from Commissioner Philip Moeller, LaFleur said, “I plan to be around for a while, so we don’t need to have any more tributes.” LaFleur, who joined the commission in July 2010, has said she plans on finishing her term, which expires in June 2019.
‘Excited’ to Work with Each Other
The congeniality between the former and current chairman betrayed no resentment over the way in which Bay took over the gavel.
While LaFleur publicly lobbied for the position after Wellinghoff’s resignation, President Obama nominated Bay last year. The choice was widely seen as engineered by then-Senate Majority Leader Harry Reid (D-Nev.), who publicly, and bluntly, said he did not want LaFleur as chairman.
Bay’s nomination received criticism from Congressional Republicans, who questioned his qualifications to be chair, as he had never served as a regulatory commissioner. Critics were also troubled that Bay would be leapfrogging the only female commissioner at the time. (See Analysis: LaFleur Cruises, Bay Bruises in Confirmation Hearing.)
The White House and Congress eventually struck a deal in which LaFleur would officially become chairman for nine months before Bay took the gavel.
Since then, LaFleur and Bay have been nothing but cordial in public.
“Congratulations to Norman Bay, who becomes Chairman April 15,” LaFleur tweeted last week. “Excited to continue working with him and all my FERC colleagues!”
“I thank former Chairman Cheryl LaFleur for her leadership at FERC and look forward to working with my colleagues on the commission and staff, as we build on the progress of the past to address the challenges of the future,” Bay said in a statement.
No Change in Routine
Besides the commissioners’ change in seating positions, FERC’s open meeting played out the same way it has for years: staff read their presentations, the commissioners thanked them and asked a few questions, and there was no debate on any issues.
During his first nine months as a commissioner, Bay made few comments and often merely thanked staff for their hard work. He was much more talkative Thursday, making several comments, albeit prewritten ones, on the import of the issues being discussed at the meetings. (See FERC Briefs.)
As has been the case over the past several months, the meeting was repeatedly interrupted by protesters opposed to the commission’s approval of natural gas infrastructure projects. After the first protester was escorted out by security, Bay quipped, “Well I guess one wouldn’t be a chairman without disruptions.”
Protesters were markedly more hostile this time around, yelling angrily at the commission as they were dragged — or sometimes carried — out by security. Each protester ended his or her tirade with a “Stop construction at Cove Point” chant.
Bay did not miss a beat while presenting his gifts to LaFleur. But after the fourth interruption, Bay made what seemed to be an impromptu statement:
“I just want to stay one thing. For the protesters out there, we respect your First Amendment rights, but just like Congress, the courts and every other federal agency, we have rules relating to the decorum of our proceedings. FERC believes in process. We welcome your views, we want to hear your views. But there are ways that you can do that. And you can do that by simply making submissions in our docketed proceedings. But interrupting these open meetings does not help your cause. It’s not even helpful in trying to get information to us, because they actually technically represent ex parte contacts. … If there are more of you in this room today who want to do some sort of disruption, please don’t.”
That plea went unheeded.
“Oh my God, we have a situation here!” cried out one protester in a mocking tone, quoting LaFleur in her comments to the National Press Club in January on the demonstrations. “The situation’s not going away! … There is no democracy here! You just ignore anything I write in the computer!”
While there were audible sighs of exasperation in the room after this final interruption, Bay remained unfazed.
Bay as Consensus-Builder?
As head of the Office of Enforcement, Bay received criticism from some members of the energy bar and former regulators for what they called his heavy-handed approach. (See PJM Trader Calls FERC on Manipulation Probe.)
As a commissioner, said attorney Michael Yuffee, “His dissents suggest that he has staked out a firm — even doctrinaire — approach to the application of federal energy law to facts.” (See related story, FERC Rejects Rehearing Request on SPP Order 1000 Filing.)
As chairman, consensus-building will have to become a bigger part of Bay’s repertoire, said Yuffee, a partner with Reed Smith who has worked for FERC’s Office of Administrative Law Judges and represented clients in matters with Enforcement.
“The peculiar circumstances of Chairman LaFleur moving back into a commissioner’s spot under Bay makes it likely Bay will try even harder to forge consensus amongst his colleagues, foremost with LaFleur,” Yuffee said.
Yuffee also said the unusual situation is unlikely to affect FERC staff members. LaFleur “didn’t have that much time to put her stamp on the direction of the commission. I think overall it probably will be business as usual.”
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.
Members of the Markets & Operations Policy Committee agreed with a staff recommendation, which found that Western Farmers’ plan to add 100 MW of wind generation did not qualify for the waiver.
