NRG Seeks Change on Huntley Reliability Contract

By William Opalka

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.

nrg 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.)

December 15, 2015

‘Connected Entity’ Proposal Too Broad, Burdensome, Market Participants Tell FERC

By Rich Heidorn Jr.

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.)

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, 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.

“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.

“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.

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.

December 15, 2015

PJM, MISO to Scrap $20M Threshold for Joint Tx Projects

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.

pjm “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.)

— Suzanne Herel

December 15, 2015

Stakeholders to ICC: MISO Resource Adequacy Fine — for now

By Michael Brooks

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.”

icc — 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 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.

December 15, 2015

SPP to Members: We’re Ready for Winter

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.”

“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.”

Staff is predicting a peak load of almost 42,000 MW and a 65% capacity reserve margin. (See related story, NERC: Tepid Demand, DR Growth Ensure Winter Readiness.)

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.

— Tom Kleckner

December 15, 2015

PJM Markets and Reliability Committee Preview

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.)

6. DEMAND RESPONSE NON-SUMMER CAPACITY COMPLIANCE CLARIFICATION (10:15-10:30)

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.)

December 15, 2015

SPP Board Approves Budget, SPC Expansion

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.

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.

spp 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.

spp 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.

spp 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

spp

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.

December 15, 2015

MISO Stakeholders OK Redesign, Begin Implementation

By Amanda Durish Cook

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.

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.

December 15, 2015

MISO Monitor Auditing Tx Outages that Caused Price Spikes

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.

— Amanda Durish Cook

December 15, 2015

Company Briefs

The El Paso City Council last week voted unanimously to reject a $71.5 million rate increase by El Paso Electric.

Unless the city and utility can negotiate a settlement by Dec. 15, which is the deadline for reaching an accord with the city, the dispute will head to the Public Utility Commission of Texas for a final decision.

The utility filed a rate increase request with the city on Aug. 10, asking for a 12% increase for residential and small commercial customers, a 24% rate increase for solar residential customers and large increases for government agencies and other classes of customers.

More: El Paso Times

Rockland Capital Illinois Plant $2 Million Behind on Taxes

Rockland Capital, owner of the Grand Tower Energy Center power plant in Illinois, told The Southern Illinoisan in a statement last week that it is “not in the financial position to make tax payments based on the current assessment.” The company has failed to pay more than $2 million in property taxes on the 490-MW combined-cycle plant to Jackson County.

Rockland has argued for a 93% reduction in assessed value, from $100 million to $7 million. The company has been battling the county on the issue for two years. “Despite our repeated attempts to negotiate in good faith — including initiating mediation efforts with a well-respected retired Illinois judge of many years and making the assessor’s office aware of the plant’s difficult financial situation — our efforts have been rebuffed,” the company said in a statement.

Jackson County Treasurer Sharon Harris-Johnson said the company has until Jan. 18 to pay the tax arrearage, which is accumulating interest. If it does not pay its back taxes by the deadline, she said, it will be subject to a tax sale.

More: The Southern Illinoisan

OCC Hearings Begin for PSO’s $169M Rate Case

The Oklahoma Corporation Commission is focusing on details of a settlement Public Service Company of Oklahoma entered into with EPA over compliance with emissions rules, which is at the heart of the utility’s request to raise rates to pay for $169 million in environmental upgrades.

Steve Fate, PSO’s director of business operations support, said the utility entered into the EPA settlement to resolve part of a federal plan imposed on Oklahoma for regional haze. The utility plans to retire one coal unit in 2016 and another coal unit in 2026 at its Northeastern Station plant to comply with the regulations.

The utility is seeking to boost customer bills by 14% next year to cover its compliance costs.

More: The Oklahoman

Xcel’s SPS Labor Force Requesting Market-Equity Raise

More than 800 employees of Xcel Energy’s Southwestern Public Service subsidiary are requesting a wage increase to keep pace with the pay of Xcel’s other operating units, a demand the company called “unreasonable and unachievable.”

Employees represented by the International Brotherhood of Electrical Workers say they are not being paid equal wages compared to employees at Xcel’s other units, including Denver-based Public Service Company of Colorado.

“Workers in our area have not had an increase in two years,” said Robert Melton, IBEW business manager. “Workers here just want to be paid equal to what everyone else with their skills are being paid.” Negotiations are ongoing.

More: Carlsbad Current-Argus

Kemper Project Costs Continue to Climb

Mississippi Power has announced it will spend another $62 million finishing construction on a coal-gasification power plant in eastern Mississippi, pushing the total cost to almost $6.5 billion.

The company said ratepayers would not be liable for the new set of overruns, which were needed to finance changes and repairs after the Kemper County power plant underwent test runs. About $4.2 billion of the project is eligible for recovery in rates. Southern Co., the utility’s parent, will write down $2.3 billion of the $6.5 billion project.

More: Associated Press

Municipal-Owned Power Plant Shuttered After 100 Years

The municipally owned Peru power plant, a coal-fired generator that has stood since 1911 and was the sole supplier of electricity to the northern-central Indiana city until the 1970s, will retire on Jan. 1.

The Peru Utilities Service Board voted Dec. 4 to shut down the plant, saying it would have been too expensive to upgrade it to comply with regulations introduced under the Clean Power Plan. The plant has only operated for a few days a year since 2009.

Now Peru’s utilities board needs to decide whether to demolish or mothball the facility. A study commissioned by the utility has estimated it would take $4.8 million to raze the plant, while a mothballed facility would cost $140,000 annually to maintain.

More: Kokomo Tribune

NRG to Shutter Illinois Coal Plant

nrg One of the Illinois coal-fired plants that NRG Energy bought out of bankruptcy last year won’t be bidding in PJM’s upcoming capacity auction and will likely be shuttered in a few years. The company said its 510-MW Will County Unit 4 is struggling to be competitive in a wholesale market dominated by low-cost natural gas and an increasing amount of low-cost renewables.

The unit is one of two remaining at the plant. Unit 3, a 251-MW coal-fired unit, was closed by NRG earlier this year. At that time, NRG said it would continue running Unit 4 as long as it was profitable. But the notice that the unit would not be participating in the capacity auction in practical terms means a permanent closure is imminent. The unit has 70 employees.

“After analyzing forecast market conditions, NRG has determined that we cannot justify continued operation of Will County Unit 4 … beyond May 2018,” NRG spokesman David Gaier wrote in an email.

More: Crain’s Chicago Business

GE to Supply Turbines for Pa. Power Plant

General Electric will supply two gas turbines for the 1,029-MW Caithness Moxie Freedom power plant in Luzerne County, Pa., which will generate enough power for nearly 1 million homes when it becomes operational in 2018.

The combined-cycle plant is being jointly developed by Moxie Energy and Caithness Energy.

GE Energy Financial Services is offering $592 million in senior secured credit facilities for the plant’s construction and operation.

More: Power Technology

PPL Names Bergstein Vice President, Treasurer

ppl PPL has named Joseph P. Bergstein its treasurer and vice president for investor relations, effective Jan. 1.

The 16-year veteran Bergstein was previously vice president for investor relations and financial planning. The move is part of a plan to consolidate functions within PPL’s corporate finance organization.

Bergstein takes the place of Mark Wilten, vice president, treasurer and chief risk officer, who will be leaving the company Jan. 31.

More: PPL

GM Assembly Plant to Tap Clean Energy in 2016

The General Motors assembly plant in Arlington, Texas, next year will derive 40% of its electricity from wind power, enough to build up to 125,000 trucks a year.

GM announced Dec. 10 it has signed an agreement with EDP Renewables of North America to purchase power from its Hidalgo Wind Farm in South Texas. Fifteen of the wind farm’s 260-foot tall turbines will be dedicated to GM’s energy needs, the company said.

More: The Dallas Morning News