The New Hampshire Site Evaluation Committee (SEC) has turned aside protests and deemed the Northern Pass transmission line application complete.
The Dec. 7 decision means the licensing process for the 192-mile line to connect Canadian hydropower with the New England energy market can continue. The committee, which voted 6-0 to accept the application, is expected to rule in about a year.
Project opponents had maintained that the application was incomplete because developers had not shown they had property access along its entire route, especially at its northernmost point. State environmental officials and a group representing independent power producers had raised questions about site access. (See Northern Pass Facing Challenges over Siting.)
But Commissioner Kathryn Bailey told a crowded hearing room that all the state agencies with permitting authority had concluded the application is complete. “I have a ton of questions about the application,” she said, according to a report by New Hampshire Public Radio, “but I’ll start the discussion by saying I think that what they’re required to provide in order for us to proceed is complete.”
In its letter declaring the application complete, the state Department of Resources and Economic Development said that the project will use existing corridors to cross five state forests under the department’s management. However, it cautioned that any “project-related impacts” to properties purchased through the Land Conservation Investment Program would require legislative action.
Also, under the federal Land and Water Conservation Act, any impacts outside of existing utility rights of way in Bear Brook State Park would require substitution of equivalent recreation properties, subject to the approval of the Interior Department.
Northern Pass Transmission, a subsidiary of Eversource Energy, was pleased with the panel’s ruling. “We appreciate the hard work that the SEC and other state agencies have put into reviewing the contents of this lengthy application, and we are eager to begin the next phase of the state permitting process,” it said in a statement.
The owner of the land alongside state highway rights of way that developers want to use said it was disappointed but not surprised. “As members of the SEC acknowledged, certain property rights are in dispute. The question is when and how those property right issues are taken into consideration by the SEC. The answer to that question is still unclear,” the Society for the Protection of New Hampshire Forests said in a statement.
The society also has filed suit in Coos County Superior Court to stop the project.
Eversource hopes to begin construction in 2017 and begin importing power from Hydro-Québec in spring 2019.
NRG Energy asked FERC last week to approve a revised reliability-must-run contract for its Huntley Power Station. The company said that it may only need to continue operating one of the two units at the 380-MW plant in Tonawanda, N.Y., to ensure grid reliability.
The company asked the commission to revise the cost-of-service agreement it filed Oct. 14, when it was anticipated it might need to keep both of its units running for up to four years until National Grid can complete transmission upgrades needed to address voltage issues.
Last week’s filing said only one unit would be required and for as little as four months beyond its scheduled March 1 retirement (ER16-81).
NRG announced in August it would close the coal-fired units outside Buffalo on March 1.
Each of Huntley’s units has a capacity of 190 MW. Under the NRG plan, Unit 67 would close on March 1, and Unit 68 would run for another four months. NRG said NYISO has agreed to this timeline. If the system operator determines a reliability need, it can unilaterally keep the plant in service for up to another three months, or until Sept. 30.
“NRG is ready to engage with the NYISO, National Grid and the [New York Public Service Commission] to establish certainty around a reliability agreement for Huntley as necessary if National Grid’s transmission upgrades are delayed,” NRG spokesman David Gaier said.
Under the proposed agreement, Huntley would be paid about $8 million per month: $3.56 million for one-twelfth of its annual fixed revenue requirement of $42.7 million, plus $4.46 million in monthly adjustments.
NRG said the plant has become uneconomic in NYISO’s energy and capacity markets due to cheap natural gas.
For the 12 months ending July 31, 2015, the plant had a gross margin — total revenues minus variable costs — of only $16.4 million compared with a cost of service of $90.3 million, according to the company. “In fact, the $16.4 million was sufficient to cover a mere 31% of the facility’s fixed operation and maintenance expenses, let alone any other component of the cost of service,” NRG wrote.
In studies released at the end of October, NYISO and National Grid said the plant, along with a second stressed NRG facility in Dunkirk, could be closed on schedule if transmission upgrades were completed on time. (See NYISO: Two NRG Plants Can Close as Scheduled.)
WASHINGTON — Electric industry officials told FERC last week that its proposal for identifying connections between companies and individuals engaged in trading in RTO markets is too broadly written and will create significant reporting burdens.
The commission’s Notice of Proposed Rulemaking (RM15-23) would require RTOs and ISOs to register market participants through common alpha-numeric identifiers, with lists of their “connected entities” and a description of their relationships. FERC said the change would help it unravel complicated market manipulation schemes. (See Are You Two Related? FERC Wants to Know.)
Matthew Picardi, Shell
Speakers at a technical conference last Tuesday called on FERC to narrow its definition of a trader and to increase the 10% ownership threshold for determining whether entities are connected.
“The proposal in its current state is vague, would create burdensome and duplicative filing requirements, and would add material operational and compliance risks for markets participants and others without providing meaningful tangible benefits,” said Matthew J. Picardi, vice president of Shell Energy North America, speaking on behalf of the Electric Power Supply Association.
David Louw, director of the Macquarie Group’s risk management unit, said the rule could reduce participation in the markets, particularly for those “who are price takers and all those for whom the sale of electricity at wholesale is not part of their core business.”
Brandon Johnson, Berkshire Hathaway
Brandon Johnson, an attorney for Berkshire Hathaway Energy’s NV Energy representing the Edison Electric Institute, added: “We don’t think that FERC has adequately justified and explained the need for this rule.”
The proposal would use Legal Entity Identifiers (LEIs), which are already used by the Commodity Futures Trading Commission and Securities and Exchange Commission to track swaps trades. FERC said the new requirements will help the Office of Enforcement police market manipulation by providing a “more complete view of the relationships between market participants and the incentives underlying their trading activities.” The initiative would also help RTO market monitors in probes of cross-market manipulation, FERC said.
‘Control’ Definition Risks False Positives
Picardi complained that the NOPR overreaches by presuming a company has control even under passive ownership or debt financing arrangements and provides no means for participants to rebut the presumption.
“The final rule should recognize the Chinese walls that exist between marketing and trading firms and their transmission company affiliates pursuant to commission rules and the codes of conduct in order to exclude these independently managed entities from the definition of connected entity,” he said. “The connections that are more remote and will pose an unnecessary burden for no benefit include fuel supply and asset management agreements or bidding and scheduling coordination service agreements that do not afford the supplier an opportunity to control the bidding or operation of its generator customer.”
Picardi cited as an example three market participants that each own one-third of a generator. The operating company, responsible for bidding and scheduling the asset into the markets, should be considered a connected entity, he said. “The other passive owners do not have any control over the operation of the plant, so they could not engage in behaviors for the benefit of other positions or entities they hold,” Picardi said.
FERC Response
In a response to some of the most frequent questions on the NOPR, FERC said it proposed the 10% threshold as a way to determine scienter, or knowledge of wrongdoing — a necessary element to proving market manipulation.
Commissioners Cheryl LaFleur (L) and Tony Clark (R)
“It is not necessary to have a controlling interest in an entity to have a motive to favor that entity. A significant financial interest could provide such a reason, even if it did not confer control,” the commission said. “Ten percent is a customary cutoff for this purpose and is used in many affiliate definitions.”
FERC said passive investors were included because it is concerned with benefit to an entity, as well as control over it. “However, we are sensitive to concerns about the burden this might impose, and welcome comments with specific examples to help us assess whether the burden might outweigh the benefits,” it said.
Fuel arrangements, tool sharing arrangements, physical maintenance arrangements and standard power purchase agreements would not be included, it said.
No Safe Harbor
PJM Market Monitor Joe Bowring said that whatever threshold FERC chooses should not be a safe harbor protection against enforcement actions. He cited the example of a company marketing power for multiple generators in which it has no equity.
PJM Market Monitor Joseph Bowring
“We’re actually concerned — not that the 10% threshold is too low — but it’s too high,” Bowring said. “Exact thresholds, I would agree, are difficult to calculate. Exact thresholds are subject to gaming. A company could limit its ownership, if they wanted to game, to 9.9%. There’s no magic about 10% or 11 or 8.”
Bowring also said FERC should give market monitoring units authority to audit connected entity filings to determine their accuracy, as it has proposed for RTOs and ISOs. “We live and breathe with this data. We know it pretty well and I think we could be helpful to you if we had that authority,” he said.
Reporting Logistics
Picardi and Duke Energy’s Matthew Jones said the filings should be with FERC or a single designee rather than to individual RTOs and ISOs.
“Based on our experience with minimum participation requirements pursuant to FERC Order 741, RTOs/ISOs will not be able to standardize the information collection process enough across markets for there to be any benefits for entities that transact in multiple markets,” Picardi said. “The basic requirements were set out by the commission in Order 741, but each RTO/ISO has implemented the order differently, and periodically each makes changes to their respective requirements that must be reviewed and confirmed each year.”
Trader Definition
Jones, managing director of analytics for fuels and system optimization for Duke, also challenged the proposed definition of a trader.
Larry Parkinson, FERC
Duke “views traders as employees who make short-term trades of power. … Duke Energy does not consider individuals who enter offer curves into the RTO/ISO as engaging in trading activities nor considers individuals negotiating long-term power purchase agreements as ‘traders,’” he said.
In its response, FERC said a trader “is the person who makes the decisions, or devises the strategies, for buying and selling physical or financial products [that] are or may be traded in the organized electric markets. It would not include a person who simply ‘pushes the button’ to make a trade, if that person has no control over or input into the decision-making process.”
Jones also said the 15-day deadline for reporting new agreements and changes to existing ones is too short. “It would be a much easier task to align the contract reporting with the [electronic quarterly report]. The same internal processes for managing compliance for EQR reporting could be used for the RTO/ISO reporting.”
Committed Capacity
Duke suggested the rules apply only to market participants that have committed capacity into an RTO or ISO. “Market participants of an RTO/ISO who have generation assets that are committed outside of an RTO/ISO rarely sell specific capacity to the RTO/ISO. The transactions done by these market participants are energy transactions and are normally done at the ‘border’ without a specific resource named,” Jones said.
Comments due Jan. 22
Comments on the NOPR are due Jan. 22.
Commissioners Cheryl LaFleur and Tony Clark attended part of the two-hour session, which was chaired by Director of Enforcement Larry Parkinson.
The commission approved the NOPR unanimously in September, but LaFleur issued a concurring statement saying she might oppose the final rule if she concludes that the reporting burdens outweigh the benefits.
As promised, PJM and MISO filed a request with FERC last week to eliminate the $20 million threshold for interregional market efficiency projects from their joint operating agreement. The threshold was identified as an obstacle to transmission projects that could ease constraints along the RTOs’ seam.
“Based on lessons learned from recently completed PJM-MISO joint planning studies, the RTOs jointly identified a number of items to address, including potential enhancements to metrics and thresholds used for interregional coordination,” the RTOs said (ER16-488).
Responding to feedback at Interregional Planning Stakeholder Advisory Committee meetings, the RTOs identified “short-term reforms” and “long-term issues” aimed at eliminating “unnecessary hurdles” to projects straddling both regions.
Elimination of the $20 million threshold was classified as a short-term change that could help PJM and MISO relieve market-to-market congestion. The RTOs requested the change become effective Feb. 8.
MISO also is considering eliminating its 345-kV minimum on such projects.
The RTOs are being pressured to take action by FERC and Northern Indiana Public Service Co., which filed a complaint in 2013 over its frustrations with the interregional planning process (EL13-88). In February, FERC said it was considering taking action “to improve the efficiency of operations” at the RTOs’ seam (AD14-3). (See Impatient FERC Hints at Action on PJM-MISO Seams Disputes.)
Resource adequacy in MISO’s Zone 4 isn’t a problem now, but it will be if the RTO doesn’t reform its markets to encourage generation development and demand response participation, speakers told the Illinois Commerce Commission at a policy session last week.
The commission called the session to inquire into the status of resource adequacy in Zone 4, which comprises Illinois south of the Chicago area. But there was universal agreement among attendees that, at least in the short term, reliability in the area would not be a concern.
“I think it’s important that there’s an agreement today that Zone 4 has sufficient capacity for today and for the short term,” said Illinois Senior Assistant Attorney General Susan Satter. “That means we’re not in a crisis situation. That means there is time to consider policy responses to assure resource adequacy going forward.”
Elizabeth McErlean (far right), legal policy adviser to ICC Chairman Brian Sheahan, speaks as MISO’s Jeff Bladen (second from right) and others listen at the Illinois Commerce Commission’s conference on MISO resource adequacy in Southern Illinois. (Source: David Giltzow, Illinois Commerce Commission)
“There won’t be a resource adequacy issue in the long term if we do what we should do as a state,” said David Kolata, executive director of the Illinois Citizens Utility Board. That is, “doing everything we can to encourage demand response and energy efficiency, [and] doing what we can to maximize and encourage distributed generation.”
Zone 4 has been the subject of controversy since MISO’s Planning Resource Auction in April, when prices cleared at $150/MW-day, compared with just $16.75 a year earlier. The nine-fold price increase prompted complaints from Illinois officials and stakeholders, including Attorney General Lisa Madigan. In late October, FERC held a technical conference on MISO’s capacity market in response to the complaints. (See MISO Stakeholder Process Under Scrutiny.) It’s also investigating whether market manipulation played a role in the jump in prices. (See FERC Launches Probe into MISO Capacity Auction.)
The danger for Illinois, and the MISO footprint as a whole, is the retirement of generation because of market design flaws in the RTO, said Independent Market Monitor David Patton.
Dean Ellis, vice president of regulatory affairs for Dynegy, compared the current situation to standing on a peaceful beach with a tsunami in the distance. He cited the retirement of the 465-MW Wood River power plant, which was scheduled to lose $20 million over the next five years. “Without forward price signaling, without an adequate price, it just can’t continue to lose that type of money,” Ellis said. Some market participants have criticized the scheduling of MISO’s capacity auction, which occurs just two months before the start of the delivery year.
Patton repeated his call for a switch to a sloped demand curve, a change supported by other stakeholders in attendance, including Ellis and Bill Berg, vice president of wholesale market development at Exelon.
“It’s well documented at FERC that a vertical demand curve produces binary prices: It’s either very, very high or very, very low,” Berg said. Those looking to develop generation in MISO will look at the prices produced by the vertical curve and wonder, “Am I going to get my money back, or would I be better off taking my money elsewhere?”
Zone 4 to PJM?
Illinois’ status as a retail-choice state — unlike the other states in MISO’s footprint — as well as the fact that northern Illinois is under PJM’s control, led some to call for Zone 4 to change RTOs.
Ellis called Illinois “the redheaded stepchild” of MISO. “It would be much more homogenous in PJM,” he said. “There’s robust retail competition in the PJM states; there is not in the MISO states. There’s robust wholesale competition that fosters programs like demand response in PJM; it doesn’t exist in MISO. … Southern Illinois belongs in a market like PJM. … No other state is bifurcated so dramatically between two ISOs.”
Greg Poulos and Bruce Campbell, representatives for DR providers EnerNOC and EnergyConnect respectively, lamented that Zone 4 was an inhospitable market for their companies.
“There’s a lot of demand response in the MISO markets … there’s very little in Zone 4,” Poulos said. “That would not be the case if it was in PJM.” Illinois being entirely in PJM would also make it easier for the ICC, as it would only have to deal with one RTO, he said.
“I would like my company to be active in [Zone 4], and that will not happen until we see the right pricing in that region,” Campbell said.
But Campbell also said that MISO could adopt some of PJM’s aspects, such as a sloped curve, without entirely becoming like PJM, such as having a mandatory forward capacity market.
SPP conducted a winter-preparedness workshop for its members last week, telling them its projections indicate it will be able to handle what few contingencies the RTO faces in the coming months.
Staff said winter operations within its balancing authority and reliability coordinator footprints are expected to be normal, with no forecast of extreme operational situations, and that transmission constraints and mitigations should be able to maintain “required reliable operating criteria.”
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“Operating capacity is expected to be sufficient throughout the season,” said SPP’s Jon Langford. He said any short-term constraints are expected to be “manageable.”
Attendees of the Dec. 10 workshop, SPP’s third such readiness seminar, reviewed relevant emergency procedures and industry-wide lessons learned. The seminars are conducted twice a year, just before the peak winter and summer seasons.
A separate session was held recently for SPP’s new Integrated System members, to help familiarize themselves with their new balancing authority.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee this 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, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
2. PJM Manuals (9:10-9:25)
Members will be asked to endorse the following manual changes:
Manual 10: Pre-Scheduling Operations. The changes define a generator planned outage and restrict scheduling planned outages during peak maintenance season; define generator maintenance outage; define unplanned outage and clarify notification requirements; and correct the definition of non-synchronized reserve.
Manual 11: Energy & Ancillary Services Market and Manual 28: Operating Agreement Accounting. Changes reflect Tariff revisions approved by FERC regarding the energy market offer cap that went into effect Monday (ER16-76). Cost-based offers for incremental energy are capped at $2,000/MWh and allowed to set prices. Costs above that cap will be recovered through an after-the-fact review and make-whole payments. Market-based offers for individual units are allowed to rise with their cost-based offers. (See PJM Members OK $2,000/MWh Energy Market Offer Cap.)
Manual 14D: Generator Operational Requirements. Revisions reflect the annual review of the manual as well as revisions to the reactive testing process. Revises and renames the wind farm communication model, making it applicable to all jointly owned resources to avoid confusion among control room operators. Adds definitions of generator planned, maintenance and forced outages.
Manual 39: Nuclear Plant Interface Coordination. Updates are the result of a three-year review and include safe shutdown loading requirements developed by the nuclear generation owners user group.
3. LOAD FORECASTING ENHANCEMENTS (9:25-9:40)
The committee will be asked to approve changes to Manual 19: Load Forecasting and Analysis that will allow distributed solar generation to be included in the load forecast. (See “Distributed Solar to be Included in Load Forecast” in PJM Planning and TEAC Briefs.)
4. LOAD FORECAST UPDATE (9:40-10:00)
Members will be asked to endorse amendments to Manual 18: PJM Capacity Market and Manual 18B: Energy Efficiency Measurement and Verification to accommodate the inclusion of energy efficiency resources in the capacity market when those resources are reflected in the peak load forecast. (See “Members Ask for More Time to Consider EE Resource Manual Changes” in PJM Markets and Reliability Committee Briefs.)
5. UNDERPERFORMANCE RISK MANAGEMENT IN RPM/CP (10:00-10:15)
Bob O’Connell, representing PPGI Fund A/B Development, will present a problem statement and issue charge related to underperformance risk management in the capacity market. It would evaluate ways for generators to minimize such penalties by netting them against over-performing generators. (See PJM Generator Risk Proposal Faces Resistance.)
The committee will be asked to approve Tariff and manual revisions that clarify the process for establishing customer baseline load for non-summer demand response under Capacity Performance rules. (See “Members Endorse Method for Measuring Non-Summer DR” in PJM Market Implementation Committee Briefs.)
LITTLE ROCK, Ark. — SPP’s Board of Directors/Members Committee approved a $280.3 million budget and a 2-cent reduction in the RTO’s administrative fee during its year-end meeting here last week.
The board accepted the SPP Finance Committee’s proposal of a 37-cent/MWh administrative fee rate for 2016, down from this year’s 39 cents/MWh. It also accepted the committee’s budget proposal, approving both measures with the unanimous support of the Members Committee on Dec. 8.
Skilton
SPP Director and Finance Committee Chair Harry Skilton said a small increase in budgeted expenses and an increase in transmission load as a result of the Integrated System’s incorporation were the two drivers behind the committee’s recommendation to lower the fee that pays the RTO’s administrative costs. (See Integrated System to Join SPP Market Oct. 1.)
“The legacy load has been dropping and is fairly flat,” Skilton said. “If it continues to be flat or goes down, we’ll have to address that.”
SPP projects a 12% increase in transmission volume to 407.2 million MWh because of the addition of the IS. The 2015 budget forecast was 353.5 million MWh.
SPP is using that 407.2 million MWh figure as one of the inputs into future projections of the fee. The RTO said its models indicate a sharp increase in the fee in 2019-2021, when it could reach the high 40s in a worst-case scenario that envisions a decrease in load and “expense growth outpacing flat transmission-service usage.” The fee is expected to gradually begin decreasing after 2021.
The 2016 budget comprises $217.1 million in operating expenses — a 3.3% increase from this year’s budget — $24.2 million in debt repayments, $17 million in FERC assessments and $22.2 million in capital expenditures. Staffing will remain unchanged at about 600.
Fellow director Julian Brix questioned the committee’s use of an incremental-based budget for operations expenses, instead of the zero-based budgeting that has been its norm in recent years.
“It’s difficult to keep [conducting] a zero-based budget every year. It’s become a little stale,” Skilton said.
Skilton noted that SPP’s budget is now linked to the operating plan. Ensuring the RTO’s strategic initiatives are now “synched” to the operating plan requires additional time to build the budget, he said.
“We’re going to give the incremental approach time,” Skilton said.
The operating plan places SPP’s 2016 activities into three categories: 1) major project investments, 2) major technology investments and 3) “keeping the lights on” (ongoing and incremental investments in its foundation activities).
SPP board Chairman Jim Eckelberger said information technology and keeping its organization “current and active” will drive future increases in the administrative fee. He suggested outside expertise be used to determine whether there are “cheaper alternatives” to IT maintenance costs.
“That’s probably not a bad idea, to have an outside group look at [IT and technology costs],” Skilton said.
Board, Members Review Survey Feedback
The year-end board meeting also featured SPP staff’s annual review of its survey of the board and members.
In presenting the feedback to the board, SPP CEO Nick Brown pointed to a difference in perception between the board and members in two areas: the board’s effectiveness in representing the organization to the stakeholder community, and the board’s evaluation and development of the CEO. The board gave itself scores of 4.8 and 5 on a five-point scale, respectively, while members scored the board at 4.2 and 4.
Brown assured his audience his performance review by the board is “quite thorough.”
“We debate the goals of the organization and whether we’re achieving those goals,” he said. “This year, we finished at 10 o’clock at night, which we’re proud of, because we normally finish around midnight.”
Of the 28 members of the Board of Directors/Members Committee, seven board members and 11 committee members submitted responses.
The board saw improved scores in 10 of its 12 metrics, with one rating dropping and another unchanged.
Stakeholder Survey
In addition to the board/members survey, SPP sent out 2,700 stakeholder surveys and received 410 responses, double the number received last year.
The score for the organizational groups’ overall effectiveness was down from 4.4 to 4.2, just above the average for the survey’s seven-year life. Individually, the 25 committees and working groups received scores ranging between and including 3.5 and 4.8.
Brown said the survey results will be reviewed by the Corporate Governance Committee before making any recommendations to the Oversight Committee to approve rosters.
“We’re asking each organizational group to look at this information and make any recommendations,” Brown said.
The average score went up in 2015 for all 10 services surveyed and three of four questions about SPP staff with one unchanged.
Michael Desselle, SPP’s chief compliance and administrative officer, said when respondents were asked about SPP’s performance in relation to other RTOs, the positive comments exceeded negative comments 132 to 100, though not all comments received in the negative category were actually negative.
“Some of the comments were the usual complaints,” Desselle said, referring to the inability to schedule day-ahead tags, staff pushing an agenda and the inability to view online presentations during SPP’s key committee meetings.
RE Survey
About half of the 88 Regional Entity compliance contacts registered in the SPP RE’s compliance database participated in a third survey asking their assessments on seven RE programs. The 46 respondents rated all programs with average scores in the “meets expectations” range, between 3.2 and 3.6 on the five-point scale.
Of the 21 respondents who interact with other REs, 5% rated the SPP RE somewhat worse, 19% rated it about the same, 43% rated it somewhat better and 33% rated it much better.
CPP Task Force Readies Official Comments to EPA
The Strategic Planning Committee asked for board and member input on its proposed response to EPA’s Clean Power Plan and the default federal implementation plan.
A task force reporting to the SPC is using a staff white paper on the proposed federal plan to formulate its response to EPA, which is due Jan. 21. Staff worked with the task force and other stakeholders to propose revisions that would mitigate the FIP’s impact on grid reliability, should it be implemented upon any states.
The draft white paper calls for regional system operators to review compliance plans to mitigate the CPP’s impact on regional planning and grid operations; EPA consultation with planning authorities and reliability coordinators in developing federal plans; a reliability safety valve in both federal and state plans; yielding to regional or state preferences before considering a blanket mass-based or rate-based approach for FIPs; and resource owners being allowed to retain allowances for retired resources under the proposed mass-based plan.
SPC Chair Mike Wise, senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative, said SPP staff is also drafting the formal comments, which the committee will approve.
“We’re open to comments from everyone,” Wise told the board and members. “You should be represented on this.”
Lanny Nickell, vice president of engineering for SPP, said staff’s comments on the FIP have “keyed on the impacts to the Integrated Marketplace and any reliability implications.”
“We were able to achieve a high level of consensus on the comments,” he said.
Expert Panel Begins Evaluations for Walkemeyer Project
Director and Oversight Committee Chairman Josh Martin said the 2016 industry expert panel is in place and ready to evaluate responses to SPP’s first competitive solicitations under FERC Order 1000. The panel will evaluate bids for the 21-mile, Walkemeyer-North Liberal 115-kV project in Kansas. (See “Board Approves New Order 1000 Evaluation Panel” in SPP Board of Directors/Members Committee Briefs.)
Martin said the panel has 90 days to do its work and is on schedule to present its results to the board and members during the April board meeting.
SPC Grows to 13 Members
The Board of Directors’ consent agenda included two revisions to its bylaws and a membership agreement change, all of which received unanimous support from the Members Committee:
The first revision expanded the SPC’s membership to 13 seats, adding a transmission-owning and a transmission-using member each to ensure “appropriate geographical representation.” The committee will now be composed of five transmission-owning members, five transmission-using members and three directors.
The second revision includes an amendment clarifying that SPP should not credit assessment fees for network-integration or point-to-point service over and above the amount of members’ monthly assessment. This over-crediting resulted in some members receiving credits against other portions of their transmission settlements statements, a $1.5 million error the RTO caught in March. SPP will file the bylaw change with FERC, where it may face opposition from two members benefitting from the current rules — Nebraska Public Power District and Kansas City Power & Light — which contend the RTO is crediting correctly.
The board also approved amendments to SPP’s membership agreement for Central Power Electric Cooperative and Mountrail-Williams Electric Cooperative, two Basin Electric Power Cooperative members embedded within the Integrated System. The amendments, which address dispute resolution, withdrawal rights and the obligation to build, mirror previously approved amendments for Basin Electric.
All three agenda items were recommended for approval by the Corporate Governance Committee in October.
CARMEL, Ind. — The Advisory Committee unanimously adopted a sleeker stakeholder process last week, shedding a structure that MISO stakeholders have called cumbersome and hard to follow.
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The redesign merges overlapping stakeholder groups and closes out completed task forces while re-evaluating existing meeting schedules. Seven groups were absorbed or consolidated in the redesign.
The model also puts an emphasis on holding joint meetings when two entities are addressing the same issue and reducing repetitive presentations through the use of MISO’s monthly informational forum. The new, pared-down process also calls for entities to cancel meetings when there is nothing pressing on the agenda.
Michelle Bloodworth, executive director of external affairs, said there was a surprising level of consensus among stakeholders. She said that it was “one of the most collaborative” interactions MISO and its stakeholders have had.
“I felt like we were on the same page,” said Bloodworth, who led the redesign effort after joining MISO in March from the American Natural Gas Association.
The undertaking launched in June with a white paper presented to the Steering Committee, including a straw man proposal as a starting point for discussions. The structure was finalized in a Nov. 3 stakeholder workshop. (See MISO Straw Man: Eliminate 10 of 27 Committees.)
‘Not Doing Extra Work if You Don’t Have to’
“I think we’ve got things pointed in a better direction, from my perspective,” said Kevin Murray, chair of the Advisory Committee.
Libby Jacobs, president of the Organization of MISO States, said it was an example of “an excellent partnership among stakeholders and MISO.”
“As the environment has matured, it was a needed measure. It’s the first step of a program of continuous improvement,” Jacobs said.
Kent Feliks, Advisory Committee representative for the Power Marketer sector, said the redesign contained “pretty logical expectations of not doing extra work if you don’t have to.”
Three-Month Transition
The redesign is expected to be implemented over the next three months. The Steering Committee will handle the day-to-day transition and make reports to the Advisory Committee, which will oversee the implementation’s general progress.
The Advisory Committee has committed to having quarterly face-to-face meetings, as opposed to the near-monthly schedule it had been operating under. Other parent entities will assess and then settle on a meeting frequency.
A day after last Wednesday’s Advisory Committee meeting, the Steering Committee voted to give parent committees authority to evaluate their subordinate groups under redesigned guidelines.
“From our perspective, this is a great step to making sure stakeholders are well positioned to address the big challenges our region faces,” Bloodworth said. “As you look at the Clean Power Plan and resource adequacy, it’s important that we’re able to have high-level policy discussions to map out what the challenges are and what MISO needs to do to address those challenges.”
The Right People in the Room
Bloodworth said the redesign is intended to separate policy discussions from technical engineering reviews.
“It’s making sure the right people are in the room at the right time,” she said.
The redesign requires the leaders of top committees to undergo training on meeting rules of order, what issues require voting action and how to conduct a vote.
“It makes a big difference in the efficiency of the meeting,” Bloodworth said.
At its meeting, the Advisory Committee also unanimously approved a pair of motions related to the redesign. As a result, the Seams Management Work Group will be kept a free-standing work group under the Market Subcommittee and the Regional Expansion Criteria and Benefits Task Force will continue to report to the Advisory Committee rather than to the Planning Advisory Committee.
“We can’t solve every issue. What we hope is by setting priorities, we’re going to focus on the most important things, which is good for MISO and good for its stakeholders,” Bloodworth said.
Texas congestion caused by outages and Minnesota’s under-scheduling of wind resources were the lone causes for concern in an otherwise stable quarter bolstered by mild temperatures, MISO’s Independent Market Monitor reported at last week’s Markets Committee of the Board of Directors.
Monitor David Patton said that at the beginning of November, gas prices were under $2/MMBtu and remained consistently low due to reported high levels of natural gas storage. Inexpensive gas contributed to lower overall instances of congestion.
“I believe that’s the lowest average monthly price we’ve seen,” Patton said.
Real-time energy prices were down 26% from 2015 at $25.08/MWh.
However, the Texas Hub faced price spikes in October and November caused by a combination of forced and planned generation and transmission outages. Hourly prices hit $350/MWh on Nov. 3 and 5, rising to about $500/MWh on Nov. 6, causing MISO to declare a local transmission emergency and recall a planned transmission outage.
MISO said October’s outages were examined and ultimately found legitimate but that it is continuing to examine the November outages.
“Because most of these price spikes are being driven by generation outages, we’re going to audit some of these outages,” Patton said.
Meanwhile, Minnesota Hub prices were driven down with high wind production, but a failure to predict all of the wind output created congestion. Patton reported that during high wind output, “congestion was frequently severe enough to generate negative real-time prices at the Minnesota Hub.” Wind day-ahead scheduling in the Minnesota market was approximately 11% lower than real-time wind output.
Patton said wind under-scheduling remains a “persistent phenomenon.”
Shawn McFarlane, executive director of strategy and enterprise risk management, said MISO’s November load averaged 67.8 GW, down 7.7 GW from last November’s colder-than-usual temperatures.
Project opponents had maintained that the application was incomplete because developers had not shown they had property access along its entire route, especially at its northernmost point. State environmental officials and a group representing independent power producers had raised questions about site access. (See Northern Pass Facing Challenges over Siting.)
Last week’s filing said only one unit would be required and for as little as four months beyond its scheduled March 1 retirement (
“Based on lessons learned from recently completed PJM-MISO joint planning studies, the RTOs jointly identified a number of items to address, including potential enhancements to metrics and thresholds used for interregional coordination,” the RTOs said (
Fellow director Julian Brix questioned the committee’s use of an incremental-based budget for operations expenses, instead of the zero-based budgeting that has been its norm in recent years.
In presenting the feedback to the board, SPP CEO Nick Brown pointed to a difference in perception between the board and members in two areas: the board’s effectiveness in representing the organization to the stakeholder community, and the board’s evaluation and development of the CEO. The board gave itself scores of 4.8 and 5 on a five-point scale, respectively, while members scored the board at 4.2 and 4.
The score for the organizational groups’ overall effectiveness was down from 4.4 to 4.2, just above the average for the survey’s seven-year life. Individually, the 25 committees and working groups received scores ranging between and including 3.5 and 4.8.
