LITTLE ROCK, Ark. — SPP’s Regional State Committee on Monday elected a 2019 slate of officers that includes Arkansas Public Service Commissioner Kim O’Guinn as its president.
The committee also said goodbye to New Mexico Public Regulation Commissioner Pat Lyons, who has served on the committee since his election to the PRC in 2010.
Lyons is term limited; however, he is running to regain his old job as New Mexico’s Commissioner of Public Lands, which he also held for eight years. A Republican and a 10-year state senator, he is in a tight race with Democrat Stephanie Garcia Richard.
“It’s been a pleasure,” said Lyons, the RSC’s longest tenured member. “I know everyone in this room cares for the affordability and reliability of electric services, and that’s what we’re about. Thank you for helping the consumer.”
Dana Murphy, chair of the Oklahoma Corporation Commission, paid tribute to Lyons and SPP Directors Jim Eckelberger and Harry Skilton, who are also stepping down from their positions. Fighting back her emotions, Murphy noted SPP staff members “no longer with us” and RSC members campaigning to retain their positions.
Murphy lost a runoff in August for the Republican nomination for Oklahoma’s lieutenant governor. After taking 45.8% of the vote in the GOP primary, she lost the runoff by more than 16 points. (See Okla. Commissioner Murphy Loses Runoff for Lt. Governor.)
“Some of you are wondering if it hurts to lose. It does,” said Murphy, who was credited with running a positive campaign. “I would rather lose with honor, than win without.”
Also elected as RSC officers were Nebraska Power Review Board Member Dennis Grennan as vice president and South Dakota Public Utilities Commissioner Kristie Fiegen as secretary. Their terms, and O’Guinn’s, begin Jan. 1.
SPP, MISO Regulators to Meet Nov. 11 at NARUC
The RSC issued its approval of goals and guiding principles brought forward by state regulators hoping to improve market coordination and seams issues between SPP and MISO.
A liaison committee comprising regulators from both the RSC and MISO’s Organization of MISO States will hold a public meeting Nov. 11 in Orlando, Fla., coinciding with the National Association of Regulatory Utility Commissioners’ annual meeting.
The committee has asked SPP and MISO to present white papers “identifying barriers to more efficient seams operations and transmission planning” and offer solutions. Those papers will be discussed Nov. 11.
The group’s goals are to:
Increase benefits to ratepayers in both markets by improving market-based transactions and operations across the seam;
Ensure equal consideration of beneficial regional and interregional projects in transmission planning, including evaluation of projects identified in the coordinated system plans;
Support the timely interconnection of new resources that includes consideration of the dynamics of both RTOs’ interconnection queues; and
Improve inter-RTO relations through state-led cooperation.
The OMS approved the goals and principles during its Oct. 25 annual meeting.
The two committees agreed this summer to work together in the hopes of helping resolve issues SPP and MISO haven’t. The task force is seen as increasing benefits to ratepayers in both markets and ensuring equal consideration of beneficial interregional projects. (See “RSC, OMS to Take Crack at Interregional Issues,” SPP Regional State Committee Briefs: July 30, 2018.)
The liaison committee includes Louisiana’s Lambert Boissiere, North Dakota’s Julie Fedorchak, Missouri’s Daniel Hall and Minnesota’s Matt Schuerger from OMS; and Kansas’ Shari Feist Albrecht, South Dakota’s Fiegen, Arkansas’ O’Guinn and Texas’ DeAnn Walker from the RSC. Iowa’s Nick Wagner, NARUC’s president-elect, serves as an ex officio member.
CAWG Addressing Cost Allocation in Wind-rich Areas
The Cost Allocation Working Group told the committee that work continues on a white paper reviewing cost allocation in wind-rich areas and determining whether changes are necessary, an issue raised by Sunflower Electric Power earlier this year. (See “Committee Takes on Cost Allocation Issues,” Mountain West, Cost Allocation Top SPP RSC Concerns.)
John Krajewski, who represents the Nebraska PRB, said the group developing the paper is analyzing rate design options that will meet FERC’s definition of “just and reasonable” rates, but that also reflect cost-causation principles.
“We want something that’s easy to explain to stakeholders and FERC, and something that is easy to administer,” Krajewski said. ”We don’t want six different vendors and five years of back billing.”
AUSTIN, Texas — ERCOT told the Texas Public Utility Commission last week that it will produce “higher quality estimates” for a major transmission project that raised the commissioners’ eyebrows with its escalating costs.
Warren Lasher, the grid operator’s senior director of system planning, said during the PUC’s Oct. 25 open meeting that staff are refining its previous studies and analyzing alternatives to CenterPoint Energy’s proposed 345-kV line project in the industrial Freeport area south of Houston.
CenterPoint’s application for a certificate of convenience and necessity included 30 alternative routes, ranging from 53 to 84 miles in length and $481.7 million to $695.2 million in costs (Project No. 48629). ERCOT’s initial study indicated a project cost of $246.7 million, leading the commission in September to direct the grid operator to take a second look at its analysis. (See PUCT Urges 2nd Look at Freeport Project Costs.)
“We’re going to have to spend some quality time thinking through our confidence … in the cost estimates we have for the alternatives that are different from the ones we presented,” Lasher told the commissioners. “We’ll do our best to provide as good an information set as we can back to the commission.”
Lasher said ERCOT is considering upgrading existing infrastructure as one alternative, which was rejected in the first study because it would create congestion “and the cost associated with congestion,” he said.
The commissioners agreed to wait on the analysis before issuing a preliminary order. Lasher said staff would need no more than three months to complete its work.
Hearing Set for Golden Spread Tx Cost of Service Case
The commission consented to a procedural schedule that sets a hearing for Golden Spread Electric Cooperative’s petition to reduce its transmission cost of service (TCOS) and wholesale transmission service rate (Docket 48500).
The PUC set a Dec. 21 discovery deadline, with a hearing scheduled Jan. 29-30 at the State Office of Administrative Hearings.
Golden Spread in June requested an annual TCOS of $2.42 million and an annual wholesale transmission rate of 3.6043 cents/kW-year to reflect the recent acquisition of transmission assets from Taylor Electric Cooperative.
Golden Spread’s last TCOS case, in 2011, resulted in an ERCOT transmission rate base of $2.54 million and a TCOS revenue requirement of $853,063.
PUC Passes Measure Modifying Energy Efficiency Savings
The PUC approved new “deemed savings” estimates for several utilities’ energy efficiency measures, which it said will “encourage additional energy efficiency projects” in the commercial and residential sectors and reduce the offerings’ expenses (Docket 48265).
The proposed calculations will serve as guidelines for estimating savings associated with the installation of program energy efficiency measures. The savings will be used to determine the incentive payments made to energy efficiency service providers.
The order applies to nonresidential door air infiltration and door gaskets for walk-in coolers and freezers, and for residential Energy Star-connected thermostats.
AEP Texas, CenterPoint Energy Houston Electric, El Paso Electric, Entergy Texas, Oncor, Southwestern Electric Power Co., Southwestern Public Service and Texas-New Mexico Power filed the request together.
MidAmerican Wind Increases Holdings to 2.7 GW
MidAmerican Wind has gained equity shares in a pair of wind farms, Blue Cloud Wind Energy’s facility near the Texas Panhandle (Docket 48386) and the Tahoka Wind Project near Lubbock (Docket 48429).
The PUC approved the transfer of undisclosed equity interests from the wind farms’ holding companies to MidAmerican Wind Tax Equity Holdings. MidAmerican owns 2.7 GW of installed generation capacity in ERCOT either directly or indirectly through affiliates or subsidiaries.
Blue Cloud will maintain a managing interest in its 148.35-MW project, which will interconnect with SPP through SPS’ transmission facilities. The 300-MW Tahoka project will connect with ERCOT through Sharyland Utilities.
WILMINGTON, Del. — PJM stakeholders last week endorsed a new rule that is likely to fuel consternation among owners of energy storage participating in the RTO’s regulation market. (See “Regulation,” PJM Operating Committee Briefs: Oct. 9, 2018.)
The rule approved by the Markets and Reliability and Members committees would effectively lower the amount of storage that can clear in the market’s hourly auctions. PJM proposed the change along with a problem statement and issue charge focused on the issue.
PJM’s performance-based regulation market, which went into effect in October 2012, splits the dispatch signal in two: RegA for slower-moving, longer-running units; and RegD for faster-responding units like batteries that operate for shorter periods. It also developed a “benefits factor” to compare the value of the two types of resources through a ratio.
In December 2015, the benefits factor was floored at 1, meaning that a megawatt of RegD would never be valued less than a megawatt of RegA. Staff then modified the regulation signal in January 2017 and removed the benefits factor floor entirely in August 2018 “based on operational analysis.” A proposal developed by PJM and its Independent Market Monitor that was endorsed by stakeholders in June 2017 would have implemented use of a “marginal rate of technical substitution” instead of the benefits factor, but FERC rejected the filing as unreasonably discriminatory against storage resources. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.)
With the benefits factor allowed to fall to zero, more megawatts of RegD would need to be substituted for each megawatt of RegA, but the resulting values create unintended price spikes. Staff explained that where the benefits factor fits into the pricing formulas, a situation can develop where “minimally effective resources” clear the hour-ahead auction with a $0/MWh offer price. When they operate, however, their adjusted lost opportunity cost (LOC), which is based on the current LMP when accounts are settled every five minutes, can “drastically increase” the clearing price, PJM’s Lisa Morelli said. Staff have seen the math result in clearing prices as high as $10,000/MWh, and there were 80 five-minute intervals between May and August when the clearing price rose above $500, she said.
PJM’s solution would reinstate a benefits factor floor of 0.1 so that the ratio would be limited to 10 MW of RegD to provide 1 MW of RegA and prevent extreme LOC escalations. Staff said the 0.1 floor would have impacted 264 hours, 2.58% of the total hours, between August 2017 and September 2018.
Gabel Associates’ Travis Stewart criticized the proposal for limiting the ability for storage resources to participate in the market by putting a floor on the replacement ratio. He said his storage-owning clients are willing to discuss ways to correct the issue that don’t limit the resources’ market access.
“This solution, I don’t really know that it gets us where PJM really wants to go,” he said.
“That revenue is a very important for some resources,” Dayton Power and Light’s John Horstmann said. “They’re kind of on the edge because of other changes PJM has made” in the market.
Susan Bruce, who represents the PJM Industrial Customer Coalition, strongly supported the measure to address unintended “aberrant and costly results.”
Both arguments seemed to resonate with Direct Energy’s Marji Philips.
“I’m not trying to drive to price outcome here; I’m trying to drive to what is best for the market,” she said, noting there is an ongoing effort in PJM’s Energy Price Formation Senior Task Force to support inflexible units and that batteries provide a “counter” to that. “I’m trying to vote the right way here, which is sort of balancing letting the right technology in versus getting the markets right.”
“It looks to me like we’re fixing the low-hanging fruit of a much larger problem,” Calpine’s David “Scarp” Scarpignato observed.
“I would agree with you,” Morelli said. “We recognize that there are some flaws in the regulation market design.”
“The underlying issues are the same that we have been discussing for over a year, so they’ve been known for a while. The effects on market prices became more common after the issues were first discussed in the stakeholder process. Changes in offer behavior can increase the frequency of inefficient high prices,” the Monitor’s Catherine Tyler said.
Morelli said fixing the problem “in a holistic manner” would require reopening the Regulation Market Issues Senior Task Force, which “given that process took well over a year, I don’t expect that that will come to a speedy conclusion.”
Instead, PJM hopes to implement the “narrowly targeted” proposal to “address this very narrow piece of the puzzle as a stop-gap measure” and then return to the issue “early next year” to resolve the issues in a way that addresses FERC’s reasons for rejecting the first attempt, she said. The change wouldn’t be implemented until FERC approves it and the ongoing settlement that resulted from the rejection is completed.
Some stakeholders questioned whether the proposal encroached on issues being addressed in the settlement proceedings, but PJM’s Stu Bresler didn’t see a “direct conflict in any way shape or form” between the two.
Horstmann suggested deferring the vote until the Dec. 6 MRC meeting to allow PJM time to quantify the market revenue impact of the proposed change and to allow more storage resources to participate in the discussion, which Philips seconded. However, PJM staff and Dominion Energy’s Jim Davis objected to a delay.
“We would like to see a vote today on the issue,” he said.
The deferral motion failed with 1.87 in support in a sector-weighted vote that had a 3.34 threshold for adoption.
An acclamation vote approved the problem statement and issue charge with one opposed and one abstention. Endorsement of the stop-gap proposal passed with 4.09 in favor in a sector-weighted vote that also had a 3.34 approval threshold. The proposal was also subsequently approved in the MC by acclamation with four opposed and two abstentions.
MISO members uneasy about the nomination of Minnesota Public Utilities Commission Chair Nancy Lange to the RTO’s Board of Directors raised concerns last week about a sitting commissioner being appointed to the oversight body.
MISO’s Principles of Corporate Governance require new directors to observe a one-year moratorium between their involvement with member companies and their election to the post. The bylaws state that a “director shall not be, and shall not have been at any time within one year prior to their election to the board either a director, officer or employee of a member, user or an affiliate of a member or user.”
While stakeholders say that Lange’s appointment would not explicitly violate the RTO’s bylaws, they pointed out during an Oct. 24 Advisory Committee conference call that Lange would have made decisions about the grid on behalf of Minnesota customers and utilities up until her election.
While a sitting commissioner is not considered either a member or a user, some sector representatives contend that Lange’s role as a regulator in a state within the MISO footprint warrants further discussion.
Lange’s term on the Minnesota PUC expires Jan. 7. MISO Senior Vice President of Compliance Services Stephen Kozey said that upon her election to the the RTO’s board, Lange would immediately resign her PUC position to avoid overlap between positions.
‘A Flare’
Members have been quick to point out that nominating a sitting member of a MISO state regulatory commission does not explicitly violate the RTO’s independence guidelines. Several also stress they are not concerned about Lange in particular.
But they do say that the situation falls into a gray area and that MISO should consider subjecting regulators to the same downtime requirement as industry officials. Multiple sector representatives, including the Independent Power Producers, Transmission-Dependent Utilities, Transmission Owners, Power Marketers and the non-voting Environmental sector voiced apprehension during the call.
Independent Power Producers sector representative Mark Volpe told RTO Insider that Lange has been “influencing and voting and making decisions” on behalf of MISO members and users in her state. He said although the nomination doesn’t breach the RTO’s bylaws, it “sends up a flare” about “the spirit of the rules and what it means to be independent.” He said the concern was “flagged by a number of IPP sector companies.”
Voting on Lange’s appointment is already underway, with polls open until Nov. 2. Incumbent board members Phyllis Currie and Mark Johnson are also on the ballot. MISO’s Nominating Committee last month decided the slate of candidates. (See MISO Board of Directors Briefs: Sept. 20, 2018.)
MISO rules require board candidates to capture a simple majority of a quorum of voting members, which currently stands at 35.
Board candidates are rarely rejected, the last instance being in the early 2000s when two incumbents were voted out. Although MISO has had former state commissioners on its board (Judy Walsh of Texas and the late Paul Hanaway of Rhode Island), the RTO has never appointed either a sitting commissioner or one from a MISO state.
MISO’s rotating Nominating Committee this year consists of board members Thomas Rainwater, Baljit Dail and Barbara Krumsiek, and RTO member representatives Megan Wisersky of Madison Gas and Electric and Commissioner Daniel Hall of the Missouri Public Service Commission.
Wisersky acknowledged the concerns in a statement to RTO Insider.
“Although the Nominating Committee followed the process correctly, many members of the Advisory Committee expressed concerns with the board nominating process itself,” she said. “They have specific concerns with the lack of a ‘cooling-off period’ for commissioners from states in the MISO footprint. Other potential board candidates, if they work for an organization that is a MISO member, do business with an organization that is a MISO member, or do business with MISO itself, must have a one-year separation from those businesses before they are eligible to run for a seat on the MISO board. State commissioners have no such requirement. These MISO stakeholders think this is inappropriate and would like to explore potential changes to the nominating rules.”
By the Book
MISO says the nomination process for the current election followed all current governance procedures.
“MISO leadership and its Board of Directors have received feedback from members that they were surprised to see a currently sitting commissioner within the MISO footprint nominated for a seat on the board. There is a waiting period of one year for potential candidates from within the industry, but that time restriction does not apply to members of state regulatory bodies,” MISO Senior Director of Stakeholder Affairs and Communications Shawna Lake said in an email. “Several parties have asked that the Corporate Governance & Strategic Planning Committee review and discuss candidate eligibility requirements.
“The questions and concerns to date have been about candidate eligibility generally, not about Commissioner Lange or her qualifications as a potential director,” Lake added.
Lange’s appointment to the board would fill a seat reserved for members with corporate leadership experience. MISO requires that six directors have corporate leadership experience in either board governance, finance, accounting, engineering or utility laws and regulation; another should have transmission system operation experience; another, transmission planning experience; and the final, experience in commercial markets and trading.
The Advisory Committee will take up the issue during its Dec. 6 meeting scheduled as part of MISO Board Week. Some stakeholders are asking that the item be discussed in the committee’s morning session, when the full board is present, as opposed to the afternoon session, when board members usually adjourn to other meetings. Committee leaders said the rotating team of members that determine agendas will decide on the timing of the discussion. In any case, the discussion will come weeks after the Nov. 15 publication of election results at MISO’s Informational Forum. Lake said Kozey will be on hand at the forum to answer clarifying questions about the election process.
Because the Advisory Committee functions strictly in an advisory role to MISO leadership, stakeholders cannot halt or alter the voting process. Multiple stakeholders declined to venture a guess as to the election outcome.
Lake said MISO has in the past adopted multiple Advisory Committee board process recommendations, including expanding the number of board member seats, adopting term limits for directors and adding stakeholder seats on the Nominating Committee.
“The AC has always been a key voice in governance processes. It has been highly effective in the past to offer stakeholder views and advice to the board via the Advisory Committee, transmission owners and Organization of MISO States chairs’ reports to the full board,” Lake said.
WILMINGTON, Del. — Stakeholders at last week’s PJM Markets & Reliability and Members committees meeting agreed to fast-track a proposal on demand response so it can potentially become effective in time for the deadlines related to the Base Residual Auction for the 2022/23 delivery year, which will be held next August.
The proposal, developed through the Summer-Only Demand Response Senior Task Force, is intended to “better value” summer-only DR by allowing the resources’ value to impact the load forecast as an alternative to participating as a supply-side resource in capacity auctions. To avoid double counting, resources that take the peak-shaving alternative wouldn’t be eligible to participate as either a DR resource or price-responsive demand (PRD) in the same year. (See Plan Would Reduce PJM Capacity Curve Through Peak Shaving.)
The proposal received 3.48 in favor in a sector-weighted vote that had a 3.34 endorsement threshold in the MRC. PJM sought and was granted permission to seek approval at the MC on the same day, a request that is usually discouraged. The proposal received 3.69 in favor in another sector-weighted vote with the same threshold. A competing proposal developed by EnerNOC that had also been scheduled for MRC consideration was retracted prior to the meeting.
PJM’s Rebecca Carroll said the same-day request was made because the necessary changes to the Reliability Assurance Agreement require approval by the Board of Managers, whose next meeting occurs before the next MC. Additional delay would mean the revisions wouldn’t get approved until the board’s February meeting.
The endorsed proposal was developed in conjunction with proposed revisions for measuring PRD, but PJM decided to delay seeking an endorsement on the PRD changes pending the outcome of the vote on the peak-shaving proposal.
Calpine’s David “Scarp” Scarpignato questioned that approach, saying he would have preferred to see them “voted together, if possible,” though he did not motion to defer the peaking-shaving vote.
“My comments are more to the stakeholders to make sure everyone understood that these proposals are meant to be tied together,” he said.
The PRD proposals received a first-read at the MRC and will be considered for endorsement at its Dec. 6 meeting. They address whether PRD should be required to reduce load in the winter like other Capacity Performance resources.
Proxy Fight
Members and staff engaged in a debate within a debate during a vote on revisions to the regulation market when a stakeholder requested time to set up voting as a proxy for another member not in attendance.
Panda Power Funds’ Bob O’Connell challenged the move, saying PJM’s policies require making that announcement by noon the day before the meeting. PJM’s Dave Anders said that requirement was simply meant to give the RTO enough time to make the necessary changes and that it’s traditionally been allowed if possible.
Direct Energy’s Marji Philips challenged that, saying she has experienced situations where she’d been told the proxy can’t be set up in time.
“You need to stop telling people that if that’s not true,” she said. “We [either] have a process or we don’t going forward.”
PJM CFO Suzanne Daugherty, who chairs the MRC, acknowledged the need for predictability.
“We do want to always give consistent feedback on the procedures,” she said.
Anders announced the issue was resolved when the market participant joined the meeting to vote without the proxy.
Day-ahead Market Timeline
Stakeholders also supported fast-tracking a proposal that would allow more time each morning to submit day-ahead bids and offers. Thanks to improved computing power, staff are able to push back the submission deadline from 10:30 a.m. to 11 a.m., PJM’s Tim Horger said.
While the proposal was only scheduled for a first read, Old Dominion Electric Cooperative’s Adrien Ford motioned for a vote on it, prompting Philips to voice concern that rules were once again being subverted. Ford acknowledged the point, saying she wouldn’t have made the proposal other than for the benefit of timing. It was also approved in the MC as part of its consent agenda.
Staff also agreed to seek expedited approval from FERC.
“PJM has heard loud and clear that the membership would like to have this implemented as soon as possible,” PJM’s Stu Bresler said.
Opportunity Cost Calculator Vote Deferred
A faceoff between PJM and its Independent Market Monitor about whose opportunity cost calculator reigns supreme might be ending amicably and without FERC involvement.
The situation escalated in August after stakeholders threatened to push through Operating Agreement changes if PJM held on to a recently enacted policy of not accepting the Monitor’s calculator in determining generators’ cost-based energy offers. The threat incentivized PJM and the Monitor to work toward a deal (See “PJM, Monitor Come to Agreement on Opportunity Cost Calculator,” PJM MRC/MC Briefs: Sept. 27, 2018.)
Prior to the MC vote on the OA changes, Bresler thanked the Monitor’s staff for providing “an extensive review” of how its calculator works and explained that the cooperation has allowed PJM to find a way to work within its existing policies to approve using the Monitor’s calculator.
“We are in a good place now as to how the two calculators can coexist,” he said.
The announcement satisfied O’Connell, who initiated the stakeholder threat, and he motioned to postpone the scheduled vote on the OA changes until the Jan. 24 MC meeting. The motion was approved.
“It’s my preference that we don’t amend the OA unless we absolutely have to,” he said.
The Monitor’s Catherine Tyler cautioned that the idea shouldn’t be taken off the table completely. The IMM has proposed alternative revisions to address the issue, as has PJM.
Market Seller Offer Cap Balancing Ratio
By the slimmest of margins, the MC declined endorsement of proposed Tariff revisions that would change how PJM estimates the expected future balancing ratio used in the default market seller offer cap.
The proposed method would take the average balancing ratios during the three delivery years that immediately precede the BRA using actual balancing ratios calculated during RTO performance assessment intervals (PAIs) of the delivery years, along with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI for any preceding delivery year with less than 360 intervals (30 hours) of RTO PAIs. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: July 11, 2018.)
“We’re in a spot where we’re not comfortable supporting this proposal,” said Susan Bruce, who represents the PJM Industrial Customer Coalition. Greg Poulos, executive director of the Consumer Advocates of the PJM States, said many of his members also can’t support it.
The measure received 3.3 in favor in a sector-weighted vote, short of the necessary 3.34. Bresler said the existing process can be used because there are PAIs from this year, which range between 80 and 90%.
“We have reviewed this with legal and the Tariff does not say anything about the scope or the region over which [the PAI] occurred,” he said. The two PAI incidents earlier this year were very localized. (See 2nd Load Shed of PJM’s CP Era Follows Closely on 1st.)
While the proposal would have been a better approach, staff believe they fulfilled the required investigation of the issue, Bresler said.
“We think we’re good,” PJM CEO Andy Ott said.
The Monitor, however, might not be as satisfied.
“We may circle back. We have concerns about using those [PAIs],” Tyler said.
The approval included a friendly amendment to the problem statement suggested by Duquesne Light’s Tonja Wicks that an additional pathway “or pathways” need to be developed for vetting issues that are contentious or must be decided quickly. Action on the plan is set to start on Jan. 1.
Nominating Committee Recommendations
Members approved nominees for the 2018/19 class of the Nominating Committee. They include: Pat McCullar of the Delaware Municipal Electric Corp. for the Electric Distributor sector; Kristin Munsch of the Illinois Citizen Utility Board for the End Use Customer sector; Scarp for the Generation Owner sector; DC Energy’s Bruce Bleiweis for the Other Supplier sector; and John Horstmann of Dayton Power & Light for the Transmission Owner sector.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 13: Emergency Operations. Revisions developed as part of PJM’s comprehensive security-threat review.
Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to address FERC approval of Tariff changes related to a new day-ahead pseudo-tie transaction product designed to address overlapping congestion for units pseudo-tied out of PJM.
Manual 28: Operating Agreement Accounting. Revisions developed to address FERC approval of Tariff changes related to a new day-ahead pseudo-tie transaction product for units that are pseudo-tied out of PJM.
RPM Credit Requirement Reduction Clarifications: Tariff language to remove an apparent overlapping credit reduction provision for qualified transmission upgrades, to clarify milestone documentation requirements for internally financed projects and to clarify that capacity market sellers should submit requests for reductions..
Transmission Constraint Penalty Factors: Joint PJM-Monitor package developed at the special Market Implementation Committee sessions related to transmission constraint penalty factors and draft Manual 11 and Manual 33 revisions, as well as OA and Tariff language. It was also approved in the MC as part of the consent agenda. (See “Transmission Constraint Relaxation Removed,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)
FERC Order 831 – Offer Caps: Manual 11 language that describes the long-term automated process for price-based offers greater than $1,000/MWh. There were seven objections from consumer advocates. (See “Automating Offer Confirmation,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)
2018 Reserve Requirements Study Results: The results recommended a 15.7% installed reserve margin and a 1.0887 forced pool requirement, both of which are decreases from last year’s recommendations. It was also approved in the MC as part of the consent agenda. (See “IRM Study,” PJM PC/TEAC Briefs: Oct. 11, 2018.)
Cost Development Manual Biannual Review: Members will be asked to endorse draft revisions to Manual 15 developed through the required biannual review, which include addressing terminology inconsistencies and updating the Handy-Whitman Escalation Index.
AUSTIN, Texas — The Organization of MISO States last week reflected on its 15 years of existence and looked ahead to how its member states can best accommodate an evolving grid.
During the organization’s Annual Meeting on Oct. 26, Executive Director Tanya Paslawski pointed out the group was established in 2003 at the time of the Eastern blackouts. “I think it’s entirely appropriate that OMS take credit that the lights have not gone out since for 50 million people,” she said to laughter.
OMS President Ted Thomas, chair of the Arkansas Public Service Commission, joked the group managed to land the meeting in “the largest city in America with a boil-water advisory,” referring to the flooding in Austin that rendered water non-potable for the week.
“That’s a mathematical improbability,” he quipped.
‘Decentralized AND Integrated’
Talk quickly shifted from past and present to the future of the bulk power system, the rise of distributed energy resources and cloudy jurisdictional issues.
Independent consultant Lorenzo Kristov, formerly principal of market and infrastructure policy at CAISO, said that while the bulk system isn’t likely to disappear anytime soon, grid defection is a possibility. But he said the grid can coexist with distributed resources, calling up a quote he attributed to author J.M. Greer: “The best way to get nothing done is to convince people they’re on one side or the other of a duality.”
“Decentralization can’t occur without the bulk power system,” Wisconsin Public Service Commissioner Mike Huebsch said.
Electrification will take place locally, at the “grid’s edge,” Kristov predicted, with urban planning and community-level programs. “Certainly, you can say that the bulk electric system isn’t where all the action is now,” he said.
Even in that environment, Kristov said it’s possible for the grid to become both “decentralized and integrated,” where the system operates in differently controlled layers. He said distribution utilities should consider becoming distribution system operators (DSOs), where the utility manages local electricity generation and use on the distribution network. Distribution owners could test the waters by rolling out the process on just one substation. In that framework, microgrids could assist a DSO with load management, Kristov said.
DERs
The discussion fit a pattern of recent OMS panels by veering to DERs and how states can best manage them.
Thomas wove together three rapid-fire analogies on how states must approach DERs, working in Southern euphemisms, hippies and holiday dinners.
He said the pace of solar adoption is increasing in his state. “In the South we say ‘fixin’ to happen. It’s not ‘fixin’ to happen. It’s happening. And if it’s happening in Arkansas, it’s happening in other places.”
Thomas contended that it’s time for state regulatory agencies to reach out to utilities to hammer out policies on the most pressing DER issues: “In the protest era of ‘make love, not war,’ we need to decide what policy we’re going to make love on and what we’re going to make war on,” he said.
He rounded out the quick speech by talking turkey: “It’s Thanksgiving. We’re trying to deal with a whole menu of policy items, and some things are hot, some things are served cold, [and] there are [dishes] ready at different times,” he said, urging states to first work on policies related to DER trends that are occurring today.
‘The Bus’
Michigan Public Service Commission Chair Sally Talberg reflected on a recent trip to observe Mexico City’s grid management, which she said was straightforward. There is one system operator and no state jurisdictions to worry about in the Mexican capital.
“Not that I’m suggesting that’s a great model, but it is simpler,” she quickly added.
Talberg quoted an unnamed PSC staffer that often says Michigan can respond to grid transformation by either “driving the bus, riding the bus or getting run over by the bus.”
“We try to ride the bus in Michigan,” Talberg said, meaning the state seeks to move on a mixture of developing some DER policies, making sure rate design is reasonable and working on how distribution systems that contain generation should be controlled.
We try to “get out of the bus to make sure the road is clear for the bus,” Huebsch said, explaining that his state aims for rules that allow DERs to crop up “organically” from customers and utilities.
In response to audience questions about when FERC will issue an order on DER aggregation — an issue left untouched by the commission’s Order 841 — Jette Gebhart, deputy director of FERC’s Office of Energy Market Regulation, said commission staff were paying a great deal of attention to the matter, though she wouldn’t comment on a possible date of an order.
MISO Executive Vice President of Markets Richard Doying predicted the RTO will significantly redesign its markets to accommodate the switch from a one-way power system to a cloud-based system. But he also said there’s increasingly scarce time to complete a redesign.
“When we think about how much time MISO has to prepare for that, it’s virtually none,” he said.
Doying said MISO already at times experiences zero-dollar energy pricing from its wind power contingent — not a sustainable situation for coal and other thermal units.
ERCOT Senior Director of Market Design and Operations Joel Mickey said the grid operator has so far successfully supervised its high influx of wind, with penetration spiking to 50% at one point in early 2017.
“If you’d asked me 10 years ago … ‘Can you handle 50% wind?’ I’d have said, ‘Hell no.’ Luckily, we’ve gotten used to it, and we’ve proven you can integrate intermittent renewables. It’s a lot of work, and we’ve gotten into the business of forecasting,” Mickey said.
Doying said MISO is researching to find the inflection point when reliability might be threatened because the RTO can no longer accurately forecast load because of nonvisible DERs. He said MISO today has 5,000 MW of distributed megawatts offered into the market, much of it not visible to the RTO.
“I don’t know where that point is, but it’s something that we are actively studying,” Doying said.
Blurred Lines
Advanced Energy Economy’s Jeff Dennis said DERs exist in a jurisdictional gray area, governed by sporadic and “nuanced” FERC precedent and the 1935 Federal Power Act, which was drafted when there was sharp distinction between transmission and distribution.
“The reality is between 1935 and today, the system has become much more interconnected,” Dennis said.
Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, made a case against direct FERC regulation of DER sales, saying states should oversee transactions to utilities and aggregators. He said sales by a DER to a local buyer, not an RTO, should be categorized as “other sales” and not wholesale sales “in interstate commerce,” as currently prescribed by the FPA.
“The current jurisdiction is a bit of a mess,” Peskoe said, contending that DERs should be categorized as “intrastate wholesale sales” so states can assume full jurisdiction.
“We know there is such thing as intrastate wholesale sales. Look at ERCOT,” he argued. “DERs are very much a local product. … I’d like to give states the flexibility to decide.”
But, he said, FERC relinquishing power over DERs is unlikely unless the commission is pressed on the issue by states and utilities.
That scenario set panelists into thinking about a complex set of hypothetical situations. Talberg said possible state jurisdiction over DERs could become muddled again when aggregators join RTOs as market participants, thus reintroducing FERC jurisdiction in the mix.
Kristov added that industry experts rarely raise the question of how DERs will be able to afford to participate in the wholesale markets, as upgrades on the distribution system are likely needed before the resources are equipped for RTO market participation. He hopes FERC contemplates the burden of those local costs if the commission allows DERs into wholesale markets.
Panelists also said they didn’t know what DER interconnection agreements to wholesale markets will look like. Some even ventured that states might be able to prohibit individual DER wholesale market participation if those DERs agree to enter a statewide aggregation program.
WASHINGTON — A public relations agency for the Consumer Energy Alliance emailed RTO Insider a couple weeks ago after we quoted the Energy and Policy Institute’s description of CEA as a “a fossil fuel-funded advocacy group.” (See Trump Nominates DOE’s McNamee to FERC.)
“CEA’s description in an [Associated Press] story from earlier this year was ‘Consumer Energy Alliance, a national advocate for energy consumers,’” the spokesperson said in an email. “We believe the AP is a more credible source.”
Well, yes, the AP is generally credible. But in this case, it was a bit too credulous.
Although CEA calls itself “the voice of the energy consumer,” a look at the group’s membership list shows 78 “Energy Providers & Suppliers,” two-thirds of them oil and gas producers and mining interests.
So, while I credit CEA for the transparency of its membership list, I was a little surprised that the group would invite scrutiny of its motives. Nevertheless, that would have been the end of the story, except for something else that CEA’s public relations person, Kristin Marcell, of SmartMark Communications, said in her email.
“Since your story referenced the Energy and Policy Institute in your description of CEA, I wanted to share more information about the institute’s background according to the Campaign for Accountability,” she said.
I felt I needed to know if I had quoted a disreputable source. So I clicked on the link. What followed was a trip down a rabbit hole into the murky world of public relations activism, “Astroturf” lobbying and “swampetition.”
It was a valuable reminder that one should not take such groups’ claimed missions at face value, particularly if they do not disclose their members and/or funders. Ultimately, these groups must be judged by what they do and the company they keep, not what they say.
As a window into this world, here’s what we learned about these three groups.
What is the Energy and Policy Institute?
CEA’s critic, the Energy and Policy Institute, describes itself as a “watchdog exposing the attacks on renewable energy and countering misinformation by fossil fuel interests.”
There’s little doubt about the group’s goals. It has taken on the Koch brothers, ExxonMobil, coal mining company Peabody Energy, and utilities American Electric Power, Dominion Energy and Duke Energy, among others. What it hasn’t done, however, is provide any information about who is funding its work.
“EPI is a dark money group: It does not appear to have nonprofit status, it is not registered with any relevant secretary of state, and no one admits to funding it,” the Campaign for Accountability said in a 2017 report that called it “just as secretive as the organizations it exposes.” CfA Executive Director Daniel Stevens summarized the findings in a July op-ed in the conservative Washington Examiner titled, “How the Energy and Policy Institute dupes the media into covering its work,” alleging that EPI “appears to be funded by interests or persons that profit financially from its work.”
Indeed, the institute provides no information on its members or financial backers, saying only that it “does not receive funding from corporations, trade associations or governments.”
Executive Director David Pomerantz, a former Greenpeace organizer, defended his group’s reticence.
“We’re clear about the kind of entities we accept money from,” he said in an interview. “We don’t take money from corporations, we don’t take money from solar companies, we don’t take money from wind companies or any other interest that could benefit from our work.”
Are you a nonprofit?
“We have a fiscal sponsor.”
Meaning you’re an affiliate of another organization?
“To be honest, we tend not to get into it because it inevitably leads to questions about who our specific funders are. And our work is pretty confrontational, with pretty powerful companies who have not been shy about attacking funders,” he said. “So we try to protect them from that. The way we describe ourselves is as a watchdog group whose funding comes from nonprofits.”
Pomerantz said EPI would not be required to disclose its donors even if it filed an IRS Form 990. In July, the IRS ended the requirement that nonprofit organizations registered under Section 501(c)(4) of the tax code as “social welfare” organizations report the names of donors who contributed more than $5,000 in a year. (Those names are redacted on the publicly viewable forms the groups file, leaving only the amounts visible.) The change did not affect nonprofit groups whose primary focus is influencing political campaigns, which remain required to report the names of large donors.
“Political spending — those donors have to be disclosed,” Pomerantz said. “That’s not the kind of work that we do.”
Pomerantz makes it clear that his group, unlike CEA, does not claim to believe in an all-of-the-above fuel strategy. “We’re passionate advocates for renewable energy and for [fighting] climate change. And the fact that we’re getting these kinds of attacks to me says that we’re being effective. I think we’ve developed a track record for our research that’s pretty rock solid, and nobody’s really attacked that. … Instead, they’re looking for these kinds of ad hominems. And I think we’ve got that no matter what, regardless of what level of disclosure we provide.”
CfA’s report on EPI was published in June 2017, about three months after EPI released reports accusing some investor-owned utilities and their trade group, the Edison Electric Institute, of conducting “a comprehensive campaign to weaken the solar energy market” by fighting net metering and using “disinformation.”
EEI spokesman Jeff Ostermayer defended the industry’s opposition to “outdated net metering policies” and said IOUs and other utilities provide “69% of all solar energy on the grid and virtually all the geothermal, hydro and wind energy.”
“A fair system of net metering means paying private solar customers the same, competitive price electric companies pay for other solar energy, instead of above-market rates that result in higher costs for all customers,” he said. “If private solar customers continue to use the energy grid — for backup power and to earn credits for selling energy back — then they should share in the costs of operating and enhancing the energy grid like all other customers.”
EPI also issued a report in May 2017 detailing how utilities pass through their EEI dues to ratepayers in their general operating expenses. “This widespread practice results in ratepayers subsidizing the political activities of EEI, with which they may not agree and from which they may not benefit,” the group said, citing utilities’ advocacy for increased fixed and demand charges.
Ostermayer said EPI has provided no evidence that EEI has failed to comply with state and federal laws addressing lobbying and expense reporting.
State regulatory commissions “conduct open and transparent regulatory rate review proceedings to determine what costs regulated energy companies can appropriately recover. … The lobbying portion of EEI’s dues, which is not recoverable, is calculated and reported each year using the Internal Revenue Code’s (IRC) definition of ‘lobbying and political activities’ as required to be reported on IRS Form 990,” Ostermayer said. “In filings required under the Lobbying Disclosure Act, EEI elects to use the same IRC definition, which broadly captures not only federal lobbying, but also state and grassroots lobbying and political activities. EEI activities in certain regulatory proceedings and communications efforts, for example, are not lobbying as defined by federal law. … EPI cannot change the definition of ‘lobbying,’ as set by law, to fit EPI’s own definition.”
EPI also reported in October 2016 that CEA has attacked policies supportive of solar energy, such as tax credits and net metering, while deliberately misleading the public with claims that it is “pro-solar.”
EEI, which is a CEA member, said it has never provided funding for the CfA and had no role in CfA’s report criticizing EPI.
What is the Campaign for Accountability?
Next, I felt I needed to learn more about the Campaign for Accountability. It was co-founded in 2015 by Anne Weismann, former legal counsel for the well-known liberal watchdog group Citizens for Responsibility and Ethics in Washington (CREW) and former CREW Chairman Louis Mayberg. Executive Director Stevens also is a former CREW staffer.
Much of CfA’s work has been similar to that of CREW in raising ethical questions about members of Congress and others. But the group also has taken on projects that suggest it may be driven in part by business interests rather than just a desire for good government.
In 2016, the organization launched “The Google Transparency Project,” which has produced reports on the revolving door between Google and the federal government, and allegations that Google-funded academics were influencing federal policymaking. In September, the group issued a report claiming to have purchased ads on Google while posing as the Russia propaganda agency that sought to influence the 2016 U.S. election.
CfA became its own 501(c)(3) in 2017, after beginning as a project of the New Venture Fund.
Unlike EPI, CfA does file a Form 990. Its filing for 2017 lists $995,000 in income from only four unidentified donors, the largest of which provided $850,000, 85% of the total. Although the filing does not list donors, Oracle — which has battled Google in an intellectual property lawsuit and other matters — confirmed in 2016 that it has contributed to CfA. CfA’s parent, the New Venture Fund, has received millions in funding from the Bill & Melinda Gates Foundation and the William and Flora Hewlett Foundation, according to reporting by Ethan Baron, of the San Jose Mercury News.
Last month, a blogger for the Computer & Communications Industry Association (CCIA) included CfA’s receipt of contributions from Oracle as an example of what he called “swampetition,” defined as “manipulating regulators into attacking one’s competition.”
It “is a strategy with adherents in Washington, Brussels and beyond, although it is rarely front-page news,” wrote Matt Schruers, CCIA’s vice president for law and policy. “Hamstringing competitors in the political swamp instead of beating them in the market is often deployed by legacy industries against disruptive upstarts,” he wrote in a blog post Sept. 28. “It can also be used by small firms to cripple larger opponents. As a result, leading businesses are common targets of swamp warfare.”
[CCIA defines itself as a nonprofit that “promotes open markets, open systems, open networks and full, fair and open competition in the computer, telecommunications and Internet industries.” Its members include Google, Samsung, Sprint and Amazon — but not Oracle, Microsoft or Hewlett Packard.]
EPI’s Pomerantz said he was puzzled by CfA’s attack on his group and its work criticizing deceptive sales and marketing practices by rooftop solar providers. “It’s so dissonant from the rest of their work, which is progressive. It certainly seems to be funded by an anti-distributed solar interest,” he said, adding that he had no evidence to back his suspicion.
In an interview, CfA’s Stevens described his organization as a “progressive watchdog group.” He said CfA began investigating EPI after seeing the group’s research cited in defense of solar, including during a 2016 campaign over a Florida ballot measure. “Their name just kept popping up, so we started to [ask] who is this group?” Stevens said.
The Florida Amendment 1 campaign, which was backed by utilities, would have added language to the state constitution that could have increased fees for solar users and insulated utilities from competitors.
The measure, on which Florida Power & Light, Duke and other utilities spent more than $20 million, failed after disclosure of a recording in which a prominent supporter of the measure acknowledged that the amendment was an act of “political jiu-jitsu,” with utilities portraying it as pro-solar. Sal Nuzzo, policy director of the James Madison Institute, told conservative activists that the amendment was “an incredibly savvy maneuver” that “would completely negate anything [pro-solar interests] would try to do either legislatively or constitutionally down the road.”
Stevens denied his group functioned as paid attack dogs. “We have put all our cards on the table,” he said. “We’re following the law exactly as designed.”
But his answers left room for other interpretations.
Q. Do you ever take funding specifically in return for a given project?
“Oh no, definitely not. We have our work, and we conduct our work, and then people are free to support our work, but they don’t get any control over what we do or who we’re looking into.”
Q. So the suggestion that, because Oracle has been at odds with Google, Oracle was funding your Google Transparency Project, that’s not accurate?
“That’s not accurate.”
Q. Do you fundraise around individual projects?
“Not that I can think of.”
Q. So your fundraising is around your overall work? You’re not fundraising around individual projects?
“I think that’s right.”
Q. When you say you think that’s right, that sounds like you’re leaving a little wiggle room.
“That’s how you characterized it, so that’s fine. … You can quote me, or you can characterize it how you want, but I said what I said.”
What is the Consumer Energy Alliance?
Having interviewed principals at CfA and EPI, I circled back to the Consumer Energy Alliance, hoping for an interview with one of its leaders. Yet, after having invited the scrutiny, CEA suddenly became reticent, saying in emails in early October that it would be unable to provide anyone for an interview and suggesting we meet with one of their executives at the National Association of Regulatory Utility Commissioners conference in mid-November. Happily, President David Holt agreed to an interview when we asked again on Oct. 24.
In addition to its 78 energy providers, CEA also lists as members five “Academic Groups” and 146 “Consumers/Business/Agriculture/Industry/End-Users” — mostly trade organizations, chambers of commerce and labor unions. It also claims to have 500,000 other “members” — individuals who have signed up on its website to receive information.
CEA’s mission, as stated on its website — is a bit muddled. It claims to be both the “voice of the energy consumer,” and to “provide consumers with sound, unbiased information on U.S. and global energy issues.” (Emphasis added.)
So, is CEA the “voice” of the consumer or is it attempting to whisper into the consumer’s ear?
“I think it goes in both directions,” Holt said. “The foundation behind the Consumer Energy Alliance is [that] energy impacts every man, woman and child in the U.S., and there was not an organization that really talked to these other economic sectors around the country — the farming community, the manufacturing sector, and transportation and small businesses, and just basic families from a personal security standpoint — [about] how we can continue environmental improvement while we meet our basic energy needs.”
EPI and other critics say CEA is neither the “voice” of consumers nor a provider of “unbiased” information to them.
CEA’s policy positions are unabashedly pro-energy development. CEA has supported increased offshore and land-based oil and natural gas drilling and the Keystone XL pipeline to deliver oil from Canadian tar sands to U.S. refineries.
Holt said all policy campaigns are decided by CEA’s nine-member board of directors, which meets monthly via conference call and twice a year in person. In addition to Holt, the all-male board includes executives from the airline, manufacturing, insurance, retail and petrochemical sectors; none has a background in consumer advocacy.
CEA’s 2016 Form 990 shows it received almost $2.6 million for the year and paid more than $1.1 million to HBW Resources, the public relations and lobbying firm Holt founded with Andrew Browning (CEA chief operating officer) and Michael Whatley (CEA executive vice president).
Houston-based Holt formerly worked for oil and gas trade publisher Hart Energy Services, the Texas Railroad Commission, the U.S. House Judiciary Committee and the U.S. State Department. He started a public affairs business in about 2004, which he said led to the formation of CEA in 2005. “And then as business continued to expand, [HBW was formed]. And now have a pretty vibrant organization with offices in … eight states around the country,” he said.
In 2011, Salon published a report detailing the role of Whatley and CEA in what it called a “stealthy public relations offensive … designed to manipulate the U.S. political system [and] deluge the media with messages favorable to the tar-sands industry.” It quoted a Natural Resources Defense Council analyst’s description of CEA as a “front group that represents the interests of the oil industry.”
According to his biography on the HBW website, D.C.-based Whatley served as a “senior advisor” to the Trump-Pence campaign and transition team and “represents companies in the energy and transportation sectors before the U.S. Congress, the federal government, agencies and state governments.” HBW reported $850,000 in lobbying revenue to the U.S. Senate in 2017, including CEA, oil and gas producer Noble Energy, and Sunnova Energy, a residential solar and battery storage technology service provider.
On Holt’s biography page, HBW’s “core expertise” is defined as “implementing and managing expansive energy-specific advocacy campaigns to generate a full complement of stakeholder, media and grassroots support for thoughtful, Holt said CEA was “absolved” in the Wisconsin case but agreed with the PSC’s decision to exclude its petition from the record — which ended the commission’s investigation into the matter.positive energy development.”
Critics such as the Center for Media and Democracy’s Sourcewatch say HBW and CEA are actually practitioners of “Astroturf” lobbying — corporate-funded campaigns that appear to be grassroots efforts.
“Anybody with a keyboard and a blog, they can kind of say anything they want to say,” Holt responded. “There have been organizations that have said this about us in the past that frankly we’ve never even responded to because it’s in a way so outlandish. … That’s not how we do business.”
In 2014, however, the Wisconsin Public Service Commission rejected a petition submitted by CEA that listed the names of 2,500 state residents it claimed opposed net metering and supported the utilities’ requests for fixed-rate increases. The PSC excluded the petition from the record after some customers complained their names had been included without their consent.
Holt said CEA was “absolved” in the Wisconsin case but agreed with the PSC’s decision to exclude its petition from the record — which ended the commission’s investigation into the matter.
In 2016, more than a dozen people complained to FERC that CEA had sent letters to the commission in their names falsely claiming they supported the proposed 255-mile Nexus gas pipeline from eastern Ohio to Ontario (CP16-22).
CEA told the Cleveland Plain Dealer it had generated the letters based on a robocall survey, but some of those named insisted they had not been called. Nexus’ developer, Spectra Energy, is a CEA member.
Holt said CEA erred in attributing the survey responses to the name of the person registered at a given phone number even if another family member answered. “Say your daughter answered the phone and … agreed [to submit a letter], it was submitted on behalf of the phone of record, which clearly is not what we want to have happen. So we’ve discontinued that. Lessons learned, and we’re continuing to get better.”
Holt’s explanation didn’t fly with Mary England, whose husband was one of those in whose name letters supporting the pipeline were sent. “My husband has been dead since 1998,” England told the Plain Dealer.
Holt told the paper that Spectra had not commissioned the Nexus campaign. Asked by RTO Insider if CEA ever raised funds for individual campaigns, he acknowledged, “Yeah, we’ve done that a time or two in the past.”
Many environmental and watchdog groups have criticized CEA’s campaigns, which include helping to defeat a fracking ban in Pennsylvania, opposing federal low-carbon fuel standards and working with EEI to lobby the Interior Department to reduce barriers to siting energy infrastructure on federal land. Its current campaigns support natural gas pipelines and oil and gas drilling offshore and in Alaska and Colorado.
Is there anyplace CEA thinks oil and gas drilling should be banned?
“I wouldn’t say one way or the other,” Holt responded, before adding. “I’m sure there are.
“I’ve been very clear we are very strong supporters of the environment. I would think that environmental considerations need to be weighed along with energy solutions in making sure we have the proper balance.”
American Electric Power said last week it will focus on smaller projects after Texas regulators put the kibosh on the company’s proposed $4.5 billion Wind Catcher project.
“We’re looking at obviously smaller segments, smaller wind farms with smaller transmission, multiple areas,” CEO Nick Akins told financial analysts during the company’s third-quarter earnings call on Oct. 25. “That’s one of the lessons learned.”
AEP canceled the massive project — which would have included a 2-GW wind farm in the Oklahoma Panhandle and a 360-mile, 765-kV transmission line — the day after the Texas Public Utility Commission rejected its application in July. (See AEP Cancels Wind Catcher Following Texas Rejection.)
Akins promised analysts they would see resource plans developed around renewables, storage and natural gas. The Columbus, Ohio-based company said in February that it wanted to reduce carbon dioxide emissions from 2000 levels by 80% by 2050.
“It will be smaller capacity segments focused on various jurisdictions, and we’ve already started that process,” Akins said.
AEP reported third-quarter earnings of $578 million ($1.17/share), compared to $545 million ($1.11/share) a year ago.
The company increased and narrowed its 2018 operating earnings guidance to $3.88 to $3.98/share, from $3.75 to $3.95/share. Akins said AEP’s projected growth rate of 5 to 7% annually was not “predicated on Wind Catcher” and it remains unchanged.
On a tumultuous week that saw the S&P 500 index lose the remainder of its 2018 gains, AEP shares finished at $72.74/share, a drop of $2.81 (3.7%) from its Oct. 24 close before reporting earnings.
Xcel Energy Just Missed Expectations
Minneapolis-based Xcel Energy announced on Oct. 25 third-quarter earnings of $491 million ($0.96/share) compared with $492 million ($0.97/share) for the same period in 2017.
Xcel just missed analysts’ expectations, as recorded by Zacks Investment Research, of 98 cents/share. The company said higher operations and maintenance expenses partially offset favorable weather conditions and sales growth.
CEO Ben Fowke told analysts that Colorado regulators’ approval of its Colorado Energy Plan provides a “model for how the clean energy transition can occur in the United States.” Under the plan, Xcel’s Colorado subsidiary plans to retire 660 MW of coal generation, replacing it with 1,100 MW of wind power, 700 MW of solar and 275 MW of battery storage.
Share prices were down 3.5% ($1.75/share) in the two days following the earnings announcement, closing at $48.51 on Oct. 26.
NextEra Earnings Up from 2017
NextEra Energy reported third-quarter earnings on Oct. 23 of $1.01 billion or $2.10/share, up from $847 million and $1.79 during 2017’s third quarter.
NextEra CEO Jim Robo said in a statement that the company’s Energy Resources development team expanded its backlog of renewable projects by a record 1.41 GW. NextEra added 850 MW of wind, 447 MW of solar and 120 MW of battery storage projects and expects to have 10 to 16.5 GW of renewable power projects within the 2017-2020 time frame.
The Florida-based company’s stock lost 1.6% of its value following the earnings announcement, ending the week down $2.77/share at $169.89.
AUSTIN, Texas — ERCOT market participants shared their thoughts with the Texas Public Utility Commission last week on how to address the energy-only market’s lack of scarcity pricing and slim reserve margins.
The consensus: There is no consensus.
Power companies and advocacy groups made their pitches during an Oct. 25 PUC technical workshop reviewing the market’s 2018 performance during a summer with an 11% reserve margin (Project 48551). Despite the tight margins and 14 system demand peaks bettering the 2016 record, the ERCOT market handled the summer heat without resorting to emergency actions.
Some participants suggested a shift in the loss-of-load probability (LOLP) used to calculate real-time reserves in ERCOT’s operating reserve demand curve (ORDC). Others suggested tweaking the ancillary services market. Still others said the market works just fine, thank you: No changes are necessary.
A common concern was that without higher prices and scarcity pricing this summer, the forward demand curve did not signal a need for additional generation.
“We view this discussion … as whether the current level of risk the signals in the energy-only market construct are delivering are considered acceptable,” said Michele Gregg, executive director of the Texas Competitive Power Advocates (TCPA), which represents generators, power marketers and retail providers. “The simple fact is that the lack of scarcity pricing only worsened the backward-dating forward curves, making future investment in dispatchable generation even more difficult.”
The TCPA recommends shifting the LOLP by up to one standard deviation, a position shared by Exelon.
“We believe the current scarcity pricing will not improve resource adequacy,” said Bill Berg, Exelon’s vice president of wholesale market development. “As we look ahead the next three or four years, it’s obvious to us the fleet is changing. A shift of one should shore up the existing fleet, support the renewable development we think is coming and leave enough new money in the market to incent new generation. We think 1.0 will keep you at a level where you can hold on for a few years.”
“We’re not afraid of high prices, when they are justified,” said Thompson & Knight attorney Katie Coleman, speaking for the Texas Industrial Energy Consumers trade association. “ERCOT is the only truly competitive market in the world, and we are proud of that. We think the market performed well this summer. We think you can expect that kind of performance to continue, because that is what the market is designed to do.”
“There’s no perfect answer here,” NRG Energy’s Bill Barnes said. “What we have is a competitive market. When there is scarcity, the prices should reflect a reliability risk. That did not match up this summer.”
Steve Reedy, the ERCOT Independent Market Monitor’s assistant director, noted several market participants had said similar generator outage rates shouldn’t be expected again in the future.
“I’ll point out that with the lower outage rates, we had a more secure, less risky system this summer, and that fed into the lower prices,” Reedy said. “Should we have the same events repeat next summer, but with our normal outage rate, we will see high prices, and we probably wouldn’t be talking about the need to change the LOLP.”
The PUC is moving quickly to address the feedback, with staff pulling together information from the workshop and written comments for a discussion by the commissioners as early as November.
PUC Chair DeAnn Walker said she wants to get an earlier start planning for the 2019 summer with ERCOT staff, market participants and other governmental agencies than she did last year. She plans to once again coordinate generator and transmission outages and ensure maintenance work is completed by May.
Walker is also scheduling time with Christi Craddick, chair of the Texas Railroad Commission, which regulates gas pipelines, to ensure the lines are operating. The two also worked together before this summer to handle pipeline outages, “but we were working on one contract, one pipeline at a time,” Walker said.
“I agree … that 2019 is going to be hard. There’s no steel in the ground coming, and everyone wants to move to Texas, but that’s a great thing. We keep getting more and more load,” Walker said. “I also believe our system and the whole dynamics of the market are changing. It’s going to be difficult down the road, and we need to think on that.”
Avangrid earnings jumped more than 25% year-over-year in the third quarter, mainly driven by increased gross margins for renewables and new transmission rate plans.
The company posted net income of $125 million for the quarter ($0.40/share) versus $95 million ($0.32/share) a year earlier. For the first nine months of 2018, net income was $476 million ($1.54/share) against $458 million ($1.48/share) in the first three quarters of 2017.
During an analyst call Wednesday, the company also said it foresees solid future growth based on its role in developing the largest offshore wind project in the country. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)
Avangrid’s 800-MW Vineyard Wind offshore project signed 20-year contracts with the Massachusetts Department of Public Utilities in August.
CEO James P. Torgerson said during the call that subsidiary Central Maine Power had obtained FERC approval for transmission service agreements for its New England Clean Energy Connect (NECEC) ahead of schedule. The project would bring up to 1,200 MW of Canadian hydropower to Massachusetts.
“Both Vineyard Wind and NECEC are on track, and we expect all permits and final approvals in 2019,” he said.
Torgerson said Maine regulators were close to granting NECEC a certificate of public convenience and necessity, but the state’s Public Utilities Commission on Friday said they would suspend hearings related to the project. (See related story, Maine PUC Move Poses Hurdle for NECEC.)
Significant Opportunities
The Vineyard project, a 50/50 partnership with Copenhagen Infrastructure Partners, calls for development in two phases. The first 400 MW will be operational at the end of 2021 for $74/MWh, with annual escalations of 2.5%, while the second phase, slated for a 2022 operations date, has a price of $65/MWh, again with 2.5% annual increases over 20 years.
Torgerson said both phases are eligible for investment tax credits and capacity payments. The company is looking at “significant additional opportunities for offshore wind” in Massachusetts, New York, Rhode Island and farther south, he said. Avangrid has a lease on 122,000 acres 24 miles offshore Kitty Hawk, N.C., enough for 2.4 GW of wind, and has secured a position in PJM’s queue to interconnect three planned 800-MW projects near Virginia Beach, Va. The development process “is moving a little quicker now” because of Virginia’s plans to solicit up to 2 GW of offshore wind by 2028, Torgerson said.
Avangrid also expects to bring 970 MW of onshore wind and solar into operation by the end of 2019 and estimates 2.7 GW of renewables development through 2022.
Regulatory Update
Torgerson also took note of FERC’s Oct. 16 ruling changing how it sets return on equity rates for transmission owners. (See FERC Changing ROE Rules; Higher Rates Likely.) The commission set a base ROE for Avangrid and other New England Transmission Owners of 10.41%. “The new ROE cap including incentives … would go up to 13.8%,” Torgerson said. “If this goes ahead as laid out by the commission, we would see a slight benefit to the higher ROE cap versus the lower ROE base. … So, 64% of CMP’s and [United Illuminating’s] transmission is currently capped at the 11.74%, and we get a benefit by going above that.”
The Maine PUC also recently found that CMP acted reasonably in preparing for and responding to the major storm that occurred in October 2017, and at the same time ordered the utility to file a rate case by Oct. 15.
“We asked for a $24 million rate increase; however, there won’t be any rate impact to customers as we use some of the tax reform liabilities and file that back to customers, so they won’t see a rate increase; yet we will get the ability to earn another $24 million in revenue at least,” Torgerson said.