ERCOT released its final winter assessment Nov. 2, indicating it has more than sufficient generation to meet an anticipated peak demand of 57,400 MW. The Texas grid operator says it has more than 79,000 MW of generation resources available.
ERCOT’s final winter Seasonal Assessment of Resource Adequacy (SARA) focused on expected reliability scenarios for December through February. It reflects forecasted expectations based on customer demand experienced during recent cold-weather events and current expectations for average weather this winter.
Warren Lasher, ERCOT’s director of system planning, said the grid expects to meet winter demand “across a broad range of operating conditions and weather scenarios … even during high-load conditions with extreme generation outages.”
ERCOT’s senior meteorologist, Chris Coleman, told reporters during a conference call that he is forecasting wetter-than-normal conditions for December and January, based on an El Niño winter pattern that “has an opportunity to be the largest on record.” In Texas, he said, that will result in cloudy weather, leading to milder overnight temperatures and morning lows.
“If, as expected, El Niño backs off in intensity by February,” Coleman said, “we could see a late-season cold pattern that drives temperatures lower across the ERCOT region.”
In February 2011, severe cold weather and unexpected plant outages forced ERCOT to call for rolling blackouts. While the grid’s reserve margin has increased since then, ERCOT has also taken other steps to minimize a repeat occurrence.
“We’re more prepared for winter-weather issues than we have been in the past,” said ERCOT spokesperson Robbie Searcy. “We’ve been spending more time on site visits and working with generation owners on their winter plans.”
The grid has also added nearly 1,100 MW of resource capacity from mostly wind projects since its preliminary winter SARA, issued in September. (See ERCOT Expects Sufficient Generation for Fall, Winter.) It said several units previously in seasonal-mothball status have returned to service and several new resources have become operational.
ERCOT last week also released its preliminary SARA for next spring, based on average springtime weather conditions over the past 13 years. The study’s results indicate the grid will also have sufficient installed capacity to meet forecasted peak demands during March-May 2016.
The grid operator estimates 1 MW of demand is typically enough to power about 500 homes during mild weather conditions and about 200 homes during summer peak demand.
FERC last week told the North American Electric Reliability Corp. to provide additional detail on its new risk-based approach to reliability compliance monitoring and enforcement.
The commission had approved NERC’s Reliability Assurance Initiative in February, saying it would allow regulators to focus resources on the most serious issues. FERC told NERC to revise its rules of procedure to define the RAI concepts and programs and provide details on NERC’s planned oversight of the program. (See New NERC Enforcement Methods Allow Self-Logging Minor Risk Issues.)
In its Nov. 4 order (RR15-2), the commission told NERC to provide additional information on the program in its annual reports, including:
performance assessments of Regional Entities under the program;
an analysis of self-logging data provided by REs “to measure the quality and consistency of self-logging across regions”; and
the types of “data driven” metrics it will track.
FERC also ordered NERC to eliminate “regulator trust” as a “success factor” in its analyses. “The notion of ‘regulator trust’ is a subjective concept that is not conducive to quantitative measurement,” the commission said. The commission also ordered revisions to the rules of procedures to set data retention requirements for self-logging data.
Commissioner Cheryl LaFleur issued a concurring statement cautioning FERC against micromanaging NERC.
“The RAI program grew out of a well-documented concern … that NERC and the Regional Entities’ reliability work was unsustainably bogged down in paperwork on relatively minor issues, which detracted from our collective ability to focus on more significant reliability matters. Going forward, I believe we must be careful not to require, as part of our ongoing oversight, the type of overly prescriptive and time-consuming analysis that the RAI program was designed to avoid,” she said.
“FERC and NERC should focus our attention on significant issues before us like cybersecurity, geomagnetic disturbances and adapting the electric grid to changes in the resource mix. We should also stay focused on the risk-based prioritization that led us to approve RAI, and not require NERC to repeatedly justify that program.”
WEC Energy Group on Wednesday reported net income of $182.5 million ($0.58/share) for the third quarter, its first reporting period since Wisconsin Energy acquired Integrys to form WEC Energy on June 29. Wisconsin Energy’s stand-alone earnings, excluding acquisition costs, totaled $0.61/share for the period, up from $0.57/share a year ago.
Revenue for the third quarter totaled $1.7 billion, with Wisconsin Energy contributing $1.07 billion and Integrys delivering $630 million.
“I’m very pleased with our post-acquisition work, and we remain highly confident that the merger will deliver tangible benefits,” CEO Gale Klappa said in a release.
At the company’s We Energies utility, residential electricity use increased by 11.5% over last year’s third quarter, while electricity use by small commercial and industrial customers rose 1.6%. Large C&I customers’ electricity use — excluding the iron ore mines in Michigan’s Upper Peninsula — increased by 0.6%.
Market-to-market (M2M) operations between SPP and MISO continue to show improvement, with the two RTOs on track for their second-lowest exchange of funds since the process began in March.
M2M is designed to improve price convergence on flowgates along the RTOs’ seams. They compensate each other for re-dispatching generation to reduce congestion in a way that reduces overall costs.
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SPP staff told the Seams Steering Committee on Nov. 5 that through Oct. 20, SPP is set to receive more than $102,000 for 504 hours in M2M during the month’s first three weeks. Since MISO compensated SPP for congestion costs with almost $7.9 million for March to May, neither RTO has incurred more than $379,000 in a month (see chart).
However, SPP’s Gerardo Ugalde said October’s M2M results will likely need to be recalculated. He said the Western Area Power Administration’s addition to SPP’s footprint Oct. 1 and several allocation changes led to errors in the M2M calculations.
SPP and MISO representatives are meeting this week to discuss whether M2M’s objectives are being met on some of the more troublesome flowgates, along with other issues.
“SPP and MISO agree on most of the principles, so now we’re to the point of developing criteria for those principles and discussing whether to apply that criteria going back to prior periods or only going forward,” said David Kelley, SPP’s director of interregional relations.
The seams committee also reviewed and made additional language changes to the Congestion Management Process baseline, which guides how SPP, MISO, PJM and several other entities manage market flows across their seams. The document is expected to be filed with FERC by Dec. 1, ending a year-long project.
“The idea is to get the parties to agree to a single baseline,” Kelley said.
The U.S. Department of Energy released its final environmental impact statement (EIS) for the Plains & Eastern Clean Line transmission project Nov. 4, clearing a major hurdle for the proposed $2 billion project.
The department said in the final EIS that it “did not identify widespread significant impacts as a result of construction or operations and maintenance of the project.”
However, Arkansas’ Congressional delegation urged Energy Secretary Ernest Moniz to delay a decision on the project until concerns they outlined in a Sept. 14 letter are addressed. Among those concerns are possible infringements on private property rights and the exclusion of MISO and SPP from control of the line.
“We are very concerned that you have not provided a thorough written response, and we need to meet with you at your earliest convenience,” the delegation — Sens. John Boozman and Tom Cotton, and Reps. Rick Crawford, French Hill, Steve Womack and Bruce Westerman — told Moniz. “The department should not have issued the [final EIS] before responding to our Sept. 14 letter.”
Transmission developer Clean Line Energy Partners said it expects a “record of decision” later this year that will determine whether and how the department will participate in the project. If approved, the department would act through the Southwestern Power Administration (SPA), a federal agency that markets hydroelectric power from 24 dams in six states.
The Plains & Eastern project stems from the Energy Department’s 2010 request for proposals for transmission projects under Section 1222 of the Energy Policy Act of 2005. Section 1222 authorizes the SPA to participate in “designing, developing, constructing, operating, maintaining or owning” new transmission in the states in which Southwestern operates, Oklahoma, Arkansas and Texas.
Environmental Endorsement
The Plains & Eastern would ship 4,000 MW of renewable energy from wind farms in the Oklahoma Panhandle through Arkansas and into Tennessee over 700 miles of HVDC transmission lines. It would interconnect with the Tennessee Valley Authority near Memphis, after dropping off 500 MW in a converter station in central Arkansas.
“The release of the final EIS marks the culmination of more than five years of work and the consideration of thousands of stakeholder comments,” said Clean Line President Michael Skelly in a statement.
Glen Hooks, director of the Arkansas Sierra Club, said the group endorses the Clean Line project because of its environmental and economic benefits. “This is a significant step toward ramping up clean wind energy in our region … and will also lead to the retirement of several dirty coal-fired power plants,” Hooks told RTO Insider.
Clean Line said the project will provide about $1 billion of private investment in Oklahoma. The Houston-based company also promised a direct investment of more than $100 million in Arkansas through the converter station near Russellville.
Conflict of Interest?
Despite that, the project has brought opposition from Arkansas landowners and government officials over the potential use of eminent domain.
A week before the Energy Department issued its final EIS, Cotton wrote to Moniz, accusing Clean Line of paying the salaries of department employees working on the statement.
“Clean Line representatives stated that they receive monthly invoices from DOE listing the names, roles and hours of DOE personnel working on their application,” Cotton wrote in his Oct. 27 letter. He claimed that Clean Line is paying the department between $10,000 and $1 million a month. “A process with consequences this serious should be conducted with integrity [and] transparency and free from blatant conflicts of interests.”
Clean Line responded that “there are many instances in which Congress has chosen to allow federal agencies to receive funds from private companies to enable the agencies to comprehensively review, assess and potentially to participate in a proposed project. The reasons for this approach are to ensure that the costs fall on the applicant and private sector, and that projects providing substantial public benefits can move forward without their costs being borne by the taxpayer.”
Meanwhile, Boozman and Womack are co-sponsoring a bill that would require the Energy Department to obtain approval from a governor, a state public service commission and any local tribal government before approving transmission projects and subsequent use of federal eminent domain. It also would require the projects to be placed on federal, rather than private, land whenever possible.
Boozman and Womack both spoke in support of the bill before a House subcommittee Oct. 28. Boozman said support for renewable energy projects “has been set back in Arkansas by a sense that a federal agency may force a transmission project for which there is no clear demand or demonstrated need.”
Clean Line said in a statement it “takes property rights very seriously” and would only use condemnation “as a very last resort after all reasonable attempts at voluntary easement acquisition have been exhausted.” The company projects it will have to spend more than $30 million to Arkansas landowners, “well above the estimated fair market value of those easements.”
ISO-NE and the New England Power Pool (NEPOOL) bar the public and the press from virtually all of their stakeholder meetings. They are the only one of the seven regional electric grid operators in the U.S. to do so.
New England is unique in its hybrid structure. NEPOOL, created in 1971, has more than 440 members (about 260 voting members) including utilities, independent power producers, marketers, load aggregators, end users and demand resource providers. ISO-NE was formed in 1997 at NEPOOL’s suggestion — and with FERC’s approval — to administer the region’s Open Access Transmission Tariff. ISO-NE describes NEPOOL “an advisory body” to the RTO.
NEPOOL’s four principal committees — the Participants, Markets, Reliability and Transmission committees — met 76 times and took almost 300 votes in 2014, according to the organization’s annual report. None of the meetings were open to the public or press.
The only ISO-NE-hosted meetings that are open are the Consumer Liaison Group, which meets quarterly; the annual Regional System Plan public meeting; and the Planning Advisory Committee, which meets once or twice monthly.
“However, virtually every PAC meeting includes presentation and discussion of material that is classified as Critical Energy Infrastructure Information (CEII),” ISO-NE spokeswoman Marcia Blomberg told RTO Insider. “As you know, CEII materials can’t be discussed publicly, reported upon or distributed.”
No other region covered by RTO Insider considers planning committee materials CEII1. In fact, we have received their blessings to reproduce documents such as transmission project maps to illustrate our articles. (Blomberg said the RTO can provide some maps and other materials that don’t disclose CEII, with determinations made on a case-by-case basis.)
NEPOOL Secretary David T. Doot told RTO Insider that while his group’s meetings are not public, “all meeting materials, including agendas, supporting materials (to the extent they are not confidential), and notices of all actions taken by each committee,” are posted on the NEPOOL website. Doot said he is willing to answer reporters’ questions before or after the meetings.
Indeed, NEPOOL provides unusually detailed meeting minutes. Its account of the Sept. 11 Participants Committee, for example, ran more than 20 pages.
We’re not suggesting NEPOOL or ISO-NE has anything to hide. So why do anything that makes it look that way?
— Rich Heidorn Jr.
1 FERC defines Critical Energy Infrastructure Information in the Code of Federal Regulations:
(1) Critical energy infrastructure information means specific engineering, vulnerability, or detailed design information about proposed or existing critical infrastructure that:
(i) Relates details about the production, generation, transportation, transmission, or distribution of energy; (ii) Could be useful to a person in planning an attack on critical infrastructure; (iii) Is exempt from mandatory disclosure under the Freedom of Information Act, 5 U.S.C. 552; and (iv) Does not simply give the general location of the critical infrastructure.
(2) Critical infrastructure means existing and proposed systems and assets, whether physical or virtual, the incapacity or destruction of which would negatively affect security, economic security, public health or safety, or any combination of those matters.
WASHINGTON — The White House convened a “Summit on Nuclear Energy” on Friday as the industry’s main trade group sounded an alarm over Entergy’s decision to shut down its FitzPatrick reactor in New York, just weeks after announcing the closure of its Pilgrim plant in Massachusetts.
The session appeared to be an attempt by the Obama administration to make up with the industry, which was upset this summer that the final Clean Power Plan did not do more to help existing nuclear plants. But with no major policy pronouncements emerging from the session, it’s unclear exactly what the industry gained. The Environmental Protection Agency’s carbon emission rule will credit states for new nuclear plants. But states losing existing plants will have to do more to meet their emission targets without the retiring reactors.
According to the Nuclear Energy Institute, nuclear power generates 63% of the nation’s emission-free electricity.
“Alarmingly, over the past three years, four reactors vital to regional economies and clean air efforts have been shut down prematurely already or will be retired prematurely within the next few years,” NEI said in a statement before the summit, referring also to Entergy’s Vermont Yankee, shut in December, and Dominion Resources’ retirement of its Kewaunee plant in Wisconsin in 2013. (See related story, Entergy Closing FitzPatrick Nuclear Plant in New York.)
“If the United States is to substantially reduce carbon emissions, we cannot afford to prematurely close any more nuclear power plants because of flawed electricity markets,” NEI continued. “At the same time, new reactor construction — including development of small modular reactors and other advanced reactor technologies — should be pursued vigorously.”
The summit featured remarks by a number of federal officials, including NRC Chairman Stephen Burns and Janet McCabe, acting assistant administrator for EPA’s Office of Air and Radiation.
McCabe offered little encouragement, saying that while “nuclear power can be a very vigorous tool” in compliance with the CPP, the rule is “not all powerful.”
“We can’t alone change the trajectory” of nuclear power’s economic competitiveness, she said.
Merchant nuclear units have suffered in RTOs’ single-price clearing markets because of low-cost natural gas and wind.
In states that engage in regional emissions trading to comply with the CPP, nuclear units should see increased revenue reflecting their carbon-free generation. Reliable nuclear plants in PJM also should benefit from the RTO’s new Capacity Performance rules because of the security provided by their on-site fuel supplies.
Also speaking at the summit was David Christian, CEO of Dominion’s generation group, who said the company will ask NRC to approve a request for a second 20-year license extension for its 1,676-MW Surry generating plant. The two-unit plant’s current licenses expire in 2032 and 2033.
Burns said the agency is working with the Department of Energy to revise its regulatory framework, which is designed for light water reactors.
“We are confident we could license a non-light water reactor under the current framework. However, because the NRC’s reactor licensing regulations and guidance documents were developed based primarily on light water reactor technologies, we recognize the potential knowledge gaps for both the staff and prospective applicants,” he said.
NiSource on Tuesday reported third-quarter income from continuing operations of $14.8 million ($0.05/share), a reversal from the Merrillville, Ind., company’s 2014 third-quarter loss of $17.2 million (-$0.05/share).
NiSource CEO John Hamrock said results for the company’s first quarter as a “pure-play” utility were “solidly” in line with expectations and indicate that the company is primed for growth. On July 1, NiSource separated itself from Columbia Pipeline Group, distributing all of the NiSource-held common stock of CPG to NiSource shareholders.
The company said it continued to plan spending $1.3 billion on infrastructure improvements in 2015, part of its $30 billion long-term investment plan.
“During the quarter, we continued our disciplined execution of infrastructure and environmental investments complemented by regulatory initiatives, which are providing long-term safety and reliability and environmental benefits,” Hamrock said in a conference call.
Northern Indiana Public Service Co. filed its first electric rate case in five years on Oct. 1. A decision by the Indiana Utility Regulatory Commission is expected in the third quarter of 2016.
It was about a year ago that RTO Insider began expanding its coverage beyond PJM to the other ISOs and RTOs in the Eastern Interconnection. We now have reporters based in PJM, SPP, MISO and New England (covering New York and ISO-NE) as well as Washington. And we’re planning to continue our expansion by initiating regular coverage of ERCOT and CAISO.
With the National Association of Regulatory Utility Commissioners holding its annual meeting this week, we thought it would be a good time to offer some perspective on our experience covering the grid operators.
The idea for RTO Insider’s focus on stakeholder meetings came several years ago, when I attended a PJM Markets and Reliability Committee meeting in Wilmington, Del., while conducting a compliance audit of the RTO for FERC’s Office of Enforcement. With dozens of stakeholders arrayed in two concentric U-shaped sets of tables equipped with microphones, the meeting room resembled the United Nations.
The stakes aren’t as large of course — only 21% of U.S. GDP is produced in the 13 states PJM serves.
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RTOs’ Hybrid Role
Like other RTOs and ISOs, PJM occupies a unique, hybrid role — not a government, but not a wholly private organization either. (See sidebar, RTOs: ‘A Form Between Government and Business.’)
RTOs make decisions worth billions of dollars, decisions that have a direct impact on the electric bills of millions of ratepayers and an indirect effect on a region’s economy.
But few who are affected by these decisions can afford to send a representative to the hundreds of meetings PJM and other RTOs hold. The mission of RTO Insider is to provide a fair, accurate account of the stakeholder debates to help those outside the room monitor issues that matter to them.
I’m certain more than a few PJM stakeholders were apprehensive when we started attending stakeholder meetings in early 2013. But — since settling a little disagreement with PJM over our publication’s original name — we have had good relations with both PJM and its stakeholders.
The relationship has been aided by the trust that resulted from PJM’s media participation rules, which require us to share stakeholders’ quotes with them prior to publication to ensure accuracy. At all but the two PJM senior committees, stakeholders also have the right to refuse permission to quote them by name or company affiliation (Section 4.5 of Manual 34).
The rules gave me my own apprehensions. But in practice, very few stakeholders invoke the quote veto. Most appreciate having their views communicated. It has also helped us limit factual errors and misunderstandings from lack of context.
In fact, we have voluntarily adopted the “quote check” as an RTO Insider Code of Conduct in MISO, SPP and NYISO, and we will do the same when we expand to CAISO and ERCOT.
New England an Outlier
Why haven’t we done so in ISO-NE? It’s not because we don’t like New England. My daughter is in law school in Boston, so I’m always looking for reasons to go there.
ISO-NE is a FERC-approved creation of NEPOOL, which began central dispatch of generation in the region in 1971. ISO-NE, created in 1997, refers to NEPOOL as “an advisory body” to the RTO.
“NEPOOL is a private organization and its meetings (including the Markets Committee, Transmission Committee and Reliability Committee) are private,” said ISO-NE spokeswoman Marcia Blomberg.
NEPOOL Secretary David T. Doot, an attorney with Day and Pitney, told RTO Insider that while there are no NEPOOL bylaws or other documents that prohibit the press, “it has been the recognized practice in the pool for the almost 30 years I have been representing NEPOOL.”
How can this be? FERC decided in Order 2000 to set only “minimum characteristics and functions” for RTOs but to allow RTOs to vary in their rules and governance structures.
We respect ISO-NE and believe it runs a first-rate operation. No RTO has a better communications department or website. NEPOOL posts unusually detailed minutes of its meetings, which are publicly available.
But these are no substitute for true transparency — the kind that can only come by allowing public and press access to stakeholder discussions. ISO-NE is as essential to its region as every other RTO, and its legitimacy depends on public trust.
We believe that ISO-NE’s fears of press coverage are unfounded, and our experience in PJM is proof. PJM’s rules were the result of a compromise between those who stressed the importance of transparency and those who feared the presence of the press would have a “chilling effect” on stakeholder discussions. Anyone who has read a single issue of RTO Insider can tell that our presence has scarcely affected the willingness of stakeholders to vigorously argue their case. This transparency also serves to undermine the claims of some critics that PJM is a shadowy “cabal” into which consumers have no input.
Is there some self-interest in our crusade for transparency? No doubt. We are in the transparency business and make no apologies about it.
The stakeholders in the regions we cover have repeatedly expressed their appreciation for RTO Insider’s commitment to accuracy and fairness. In fact, our business model requires it. Our subscribers include state regulators, consumer advocates, environmental groups and industrial consumers as well as transmission owners and independent power producers. None would subscribe if they didn’t believe us to be both balanced in our coverage and accurate on the details. (That is not to say we always get it right, as evidenced by the two corrections in this week’s newsletter.)
ISO-NE and NEPOOL aren’t the only organizations who could improve their transparency.
At a FERC technical conference last month on MISO’s capacity market, Tyson Slocum, director of the energy program at consumer group Public Citizen, complained that attending stakeholder meetings by phone was an inadequate way to participate because speakers fail to identify themselves.
“There is no transcript made available of these meetings at any time. As a result, there is very little public record about the details of what is driving decisions within this process,” he said. “It is essential that as a part of any capacity market reform that you look at stakeholder process reform because you are entrusting a private organization to represent all shareholders that are affected by policy.”
We’d also like to see NYISO change its rule prohibiting reporters from covering meetings except in person. (While we prefer to cover meetings in person, it is not always possible.) We’d also like to see PJM’s Board of Managers meet in public, as MISO’s and SPP’s do to no ill effect. And we’d like to see all restrictions on audio recordings eliminated. (Having a recording only helps us ensure accuracy.)
That said, ISO-NE/NEPOOL is the outlier among the RTOs and ISOs in the U.S. We take no pleasure in singling them out and hope we won’t have to report a similar disparity a year from now.
So to those within ISO-NE and NEPOOL who are opposed to opening your meetings, we say, let us in. The water’s fine.
LITTLE ROCK, Ark. — The SPP Board of Directors and Members Committee approved the 2017 Integrated Transmission Planning 10-Year Assessment’s scope, which had been revised to account for pending North American Electric Reliability Corp. transmission planning standards. The scope, which was recommended by the Markets and Operations Policy Committee, was approved with three no votes during their quarterly meeting Oct. 27.
The board and members discussed whether fluctuating gas prices, one of the assessment’s sensitivities (along with demand levels and final reliability and stability assessments), would result in a drain on staff’s time and increased study costs.
“How can you assess the demand on gas prices when you’re looking that far into the future?” asked Stuart Solomon, COO of Public Service Company of Oklahoma.
Myers
Alan Myers, chairman of the Economic Studies Working Group, said the study’s scope uses a $6/MMBtu price for gas 10 years in the future and tries to account for the impacts of increased liquefied natural gas exports and decreased fracking.
The assessment currently assumes a high availability of natural gas due to fracking. It also will consider three futures: a regional Clean Power Plan, a state-level CPP solution and an assumption the CPP is not implemented. The 2020 and 2025 models will include the CPP’s interim goals that begin in 2022 and 2025-2027, respectively.
Enhanced Combined Cycle Project Moves Forward
Natural gas prices were also at issue in the board and committee’s approval of revised Tariff language clarifying the design of the enhanced combined cycle (ECC) project, an effort to provide more sophisticated modeling that captures such plants’ flexibility. The revisions limit the number of combined cycle configurations at registration to three, tweaks the market-clearing engine’s algorithm to account for overlapping commitment periods between the day-ahead and real-time markets, and makes simplifications to ensure the project’s timely and on-budget completion.
“With gas prices where they are today, how is the ECC project going to achieve efficiencies?” asked American Electric Power’s Richard Ross. “Theoretically, [the savings] will be much smaller than what we started with, which was gas in the $4-5 range.”
Other stakeholders said the Tariff change was needed and should be approved. “Holding up the ECC cleanup revision is not the right way to move forward,” said Dogwood Energy’s Rob Janssen.
Janssen reminded members they moved forward with the ECC project not only because of the current cost-benefit analysis, “but also with the expectation the SPP system moves toward more natural gas-fired capacity in the future.”
Ross said SPP would achieve more by moving the deadline for day-ahead offers to 9 a.m. and compressing the commitment time to four hours. This summer, both SPP’s board and the MOPC voted to move the deadline for day-ahead offers up 90 minutes to 9:30 a.m. CT. (See “Board Approves Gas-Electric Timeline Change,” in SPP BoD/Members Committee Briefs.)
Ross said AEP was a no-vote against the ECC-cleanup language because it understood that the ECC project and further gas-electric harmonization couldn’t proceed in tandem, with the latter being the higher priority.
“It may have been a breakdown in communications,” Ross said, “but we understood we couldn’t advance the gas market-clearing logic any further and also implement the ECC.”
Bruce Rew, SPP’s vice president of operations, said the RTO believes it can complete the gas-electric harmonization work by next fall and complete the ECC logic by March 2017. The two projects are expected to cost a combined $7.7 million.
“Our own constraint is whether we can go down to four hours,” Rew said. He said SPP’s market-clearing engine is currently able to work with a 4.5-hour compressed timeline. He agreed to report back in January’s meeting as to “what we can do with this current technology.”
The ECC project was delayed last year to allow for a more thorough cost-benefit study. SPP has estimated it will take approximately $1.5 million and 14 months to implement the changes, which would require new software.
AEP has said it believes the ECC logic “is unlikely to resolve the challenges of combined cycle operation,” saying SPP’s market solution-engine is “already among, if not the, most complicated and computationally intensive such algorithms in the country.”
Lone Interregional Project Approved
The board and Members Committee approved the MOPC’s recommendation to approve one of three interregional projects evaluated as part of a regional review with MISO, the South Shreveport-Wallace Lake rebuild. The 11-mile 138-kV project addresses area congestion in northwestern Louisiana and has an estimated cost of $18.5 million — of which SPP would fund 20% ($3.7 million) — and a benefit-to-cost ratio of 11.86, far exceeding the 1.0 threshold.
MOPC Vice Chairman Paul Malone, of the Nebraska Public Power District, reminded the board that MISO has yet to act on approving the project and its Planning Advisory Committee did not support the project.
Eckelberger said he understood his MISO counterpart, Judy Walsh, is still open to the project. He said he will send Walsh a letter to “see if we can get this rolling.”
Eckelberger also said, “We think we’ll have to change some numbers to get MISO to work with us.”
The other two projects in the regional review are the Alto-Swartz series reactor and the Elm Creek-NSUB 345-kV transmission line. Both could be reevaluated in a future regional or interregional study.
Annual Meeting of Members
Calling the previous 12 months “another interesting year for the corporation and our members,” SPP CEO Nick Brown ticked off the Integrated Marketplace’s successful performance, recent transmission investments and the addition of 10 new members through the Integrated System’s incorporation as achievements during his annual president’s report.
Brown credited the Integrated Marketplace with creating $300 million in savings off of a $100 million investment, saying “nothing speaks more to our value to members” than seeing the markets credited for savings in members’ rate cases, annual reports, press releases and news stories.
Brown (left) and Eckelberger.
“If ever there’s a success metric, it’s that,” Brown said.
The annual meeting began with members voting to re-elect two board members, a Regional Entity trustee and five members of the Members Committee, while also unanimously accepting a Corporate Governance Committee recommendation to increase their compensation.
Board members saw their annual retainers doubled to $30,000, with Board Chairman Jim Eckelberger’s retainer increased by $15,000 to $35,000. Members approved slightly smaller increases for meeting participation and RE trustee compensation.
Members re-elected Eckelberger and Harry Skilton to three-year board terms and Dave Christiano to another three-year term as an RE trustee. They also approved a recommendation to expand the RE trustee membership to four “in the interest of succession.”
Members re-elected Kelly Walters (Empire District Electric Co.), Mike Wise (Golden Spread Electric Cooperative), Kevin Smith (Tenaska) and Tom Kent (Nebraska Public Power District) to three-year terms on the Members Committee. Also re-elected was Bob Harris (Western Area Power Administration-Upper Great Plains), who was elected to fill a vacancy earlier this year.
Brett Leopold (ITC Great Plains), Scott Heidtbrink (Kansas City Power & Light) and Jason Atwood (Northeast Texas Electric Cooperative) were all elected to their first three-year terms.
Board Approves New Order 1000 Evaluation Panel
The board followed a unanimous members’ vote to approve the Oversight Committee’s recommendation for the 2016 industry expert panel (IEP), which will evaluate proposals for SPP’s competitive solicitations under FERC Order 1000.
SPP recently asked FERC to allow it to waive Tariff provisions governing the IEP’s selection (ER16-126). It has proposed using one of its 2016 panelists to replace a 2015 candidate who may not be able to serve.
The panel was to begin its evaluation this week of bids for the 21-mile, Walkemeyer-North Liberal 115-kV project in Kansas. (See SPP Issues RFP for 115-kV Transmission Project.) It will recommend a winning proposal and an alternate proposal to the SPP board.
IEP renewals from 2015 include financial consultant William Steele, rate expert Denis Bethel, transmission analyst Michael Jacobs, NERC-compliance consultant Raj Rana, planning engineer Ronald Brown, regulatory expert Steve Strickland, former Kansas Corporation Commissioner Tom Wright and former NERC vice president Dave Nevius.
The new IEP applicants are economist Monica Kachru, former Heartland Consumers Power District CEO Michael McDowell, regulatory veteran Murry Witcher, former SPP lead engineer Bob Lux, power-systems consultant Ali Al-Fayez and engineering consultant Kirk Patterson.
Finance Committee Chair Harry Skilton said an administrative fee of 39 cents/MWh “is still realistic,” based on SPP’s draft budget for 2016.
The administrative fee, which is collected through charges to transmission customers, funds SPP’s ongoing operating costs. The budget will be voted on during the board’s December meeting.
SPP in recent years has used a 10:1 ratio to describe the benefits members receive for every dollar they put in. However, Mike Ross, the RTO’s senior vice president of government affairs and public relations, is working on a “comprehensive dialogue and story” of transmission’s value, according to Brown.
“We want to know the true value of the transmission we invest in, the value we offer with and without that transmission,” Brown said.
HR Committee Sets Merit-Compensation Increase
Josh Martin, chair of SPP’s Human Resources Committee, said the group has set SPP staff’s merit-increase budget pool at 2.5% of projected 2015 base salaries.
He said the committee has also tightened the performance compensation plan’s metrics and revised its measurements for “simplicity and alignment” with SPP’s strategic initiatives. The plan will now measure cost control, NERC violations, operating metrics and the annual customer-satisfaction survey.
Martin said SPP’s 401(k) program has been able to save $40,000 annually with a revised fee structure for its advisers. He also noted a 96% employee participation rate in the 401(k).
