ERCOT on Monday approved Luminant’s proposal to dispose of nearly 2,300 MW of coal-fired generation capacity in Texas.
The ISO’s reliability assessments determined that none of the four units at the company’s Big Brown and Sandow plants was “required to support ERCOT transmission system reliability.”
ERCOT said the Texas grid is undergoing “significant change,” with new technologies “changing the role that some older generation resources play in grid and market operations.” The ISO said lower natural gas prices have been reducing revenues for all generators in recent years, and wind and solar resources continue to flood the market.
As of Oct. 30, ERCOT has nearly 48 GW of new generation projects under study, and more than 21 GW of new projects have interconnection agreements. That includes more than 10 GW of proposed gas-fired projects, 2 GW of utility-scale solar and more than 8.7 GW of wind projects.
ERCOT has said it will have almost 81 GW of total capacity available this winter, more than enough to meet a projected peak of more than 61 GW. It will update the expected reserve margins for 2018 and the next several years in the next Capacity, Demand, and Reserves Report, scheduled for Dec. 18.
The Public Utility Commission of Texas has also directed the ISO to study and consider the appropriate level of reserves needed to maintain reliability while minimizing costs in its energy-only market.
Big Brown’s two units date back to the early 1970s and are capable of 1,150 MW of output. Vistra has said it is exploring a sale of the site north of Houston, but the plant will be shut down if it hasn’t been sold by Feb. 12, 2018.
Sandow’s units date back to 1981 and 2009 and have 1,137 MW of capacity. They will be closed Jan. 11.
Combined with the earlier retirement of Monticello’s three coal units, Luminant will have shuttered 4,167 MW of coal capacity by early next year — more than half of its 8,000 MW of available capacity. The company has only two coal plants left: Martin Lake (2,250 MW) in East Texas and Oak Grove (1,600 MW) in the southern part of the state.
Exelon will relinquish four Texas natural gas plants to its lenders and pay $60 million to keep a fifth plant in the latest response to what the company called “historically low power prices” in the state.
The plans were detailed in a Chapter 11 bankruptcy filing Nov. 7 by ExGen Texas Power, Exelon’s merchant generation business in Texas, and in an 8-K filing by Exelon. It follows Vistra Energy’s announcements last month that it would retire 4,100 MW of coal-fired generation in the state.
The 738-MW Wolf Hollow facility in Granbury, Texas, is one of the four power plants in the state Exelon will sell as part of the bankruptcy of its ExGen Texas Power subsidiary. | GE Power
Exelon said it made the bankruptcy filing to offload most of a $675 million loan due in September 2021. “Pending a competitive bidding process,” the company said in a statement, it will pay $60 million to lenders to keep its 1,265-MW Handley Generating Plant in Fort Worth.
“Lenders have agreed to exchange the debt they currently hold in EGTP’s other four plants for equity in the plants, effectively taking ownership of these facilities,” Exelon said.
The company told the Securities and Exchange Commission that it expects a pre-tax gain of $125 million to $200 million in the fourth quarter off the sale. It had recorded pre-tax impairment charges of $418 million in the second quarter of 2017 and $40 million in the third quarter for the plants.
The other four plants are the 738-MW Wolf Hollow combined cycle facility in Granbury; the 510-MW Colorado Bend combined cycle in Wharton; the 808-MW Mountain Creek steam boiler in Dallas; and the 156-MW simple cycle facility in La Porte.
The company has been seeking to sell its Texas fleet since at least March, when Reuters reported that it had hired a debt restructuring adviser to help it evaluate its options. This followed a January decision by Moody’s Investors Services to downgrade EGTP’s debt from B2 to Caa1.
Exelon’s stock closed at $41.27/share Tuesday, up 1.45% from Monday’s close.
Independent Market Monitor Beth Garza told ERCOT’s Board of Directors last month that the Vistra retirements will result in higher prices and lower capacity margins, citing two years of “clearly unsustainably low prices with high reserve margins.” (See ERCOT IMM: ‘Fat and Happy’ Times Ending with Coal Closures.)
Nuclear and coal generators made their closing argument for price supports Tuesday, as opponents urged FERC to reject the proposal or let RTO stakeholders take up the resilience debate.
Tuesday was the deadline for reply comments in response to the Department of Energy’s Notice of Proposed Rulemaking, which called for cost-of-service pricing for coal and nuclear generators in competitive markets (RM18-1). The deadline for initial comments was Oct. 23. (See FERC Flooded with Comments on DOE NOPR.)
The Rule of Three
Three-step proposals were all the rage in the latest filings, with the Nuclear Energy Institute calling for a cost-of-service mechanism to prevent “premature” retirements, an order requiring RTOs to promptly improve their price formation rules, and a long-term program for ensuring that organized markets value resilience.
Exelon, which is the beneficiary of nuclear subsidies in Illinois and New York, had its own three-step proposal, starting with “immediate action” to correct “inaccurate price signals [for] fuel-secure resources,” including ordering PJM to make energy market reforms within 90 days. RTOs and ISOs also would be prevented from mitigating the capacity market bids of plants receiving zero-emission credits “or other support payments.”
FERC should follow those actions, the company argued, with an order requiring RTOs to report on their systems’ vulnerabilities to high-impact, low-frequency events. Lastly, it said the commission should use that data, “together with threat analysis from the national security and intelligence communities, to establish a design basis threat (DBT) that can inform cost-effective market reforms.” The DBT would provide a resilience benchmark and a basis for developing solutions, the company said.
The last two steps of Advanced Energy Management Alliance’s proposal were like those of Exelon’s, with the opening of a resilience proceeding and reporting by RTOs.
But the group, which represents distributed energy resource companies and storage providers, had its own idea for step one: “Eliminate barriers to storage and distributed energy resource participation” by finalizing FERC’s November 2016 NOPR (RM16-23). (See FERC Rule Would Boost Energy Storage, DER.)
The commission received hundreds of responses to the DOE NOPR. FERC staffer Patrick Clarey told the SPP Board of Directors meeting Oct. 24 that the commission had received more than 700 comments; AEMA said it had counted “roughly 750 sets of comments.”
Congress Weighs in
Among the most recent responses were dueling submissions from members of Congress, with Republicans generally supporting the proposal and Democrats mostly in opposition.
Illinois Republican Reps. Mike Bost, Rodney Davis and Darin LaHood said “the proposed DOE rule makes critical strides toward correcting faulty market designs and valuing the role of baseload generation.”
Rep. Joyce Beatty (D-Ohio) joined with David Joyce and 10 other Ohio Republicans to warn that premature plant closings “have resulted in an electrical grid with weakened resiliency and a diminished ability to respond to crisis.”
New Jersey Republican Reps. Frank LoBiondo and Leonard Lance expressed fear that the state could lose its nuclear generation — the source of almost half of its electricity.
Hope Creek Nuclear Generating Station in New Jersey
Rep. Jerry McNerney (D-Calif.) and 13 other Democrats from his state, Pennsylvania, Hawaii, New York, Massachusetts, North Carolina, Virginia and Vermont expressed “serious concerns with the proposal and its timeline.”
They cited DOE data showing outages resulting from extreme weather increased 10-fold from 1984 to 2012 and doubled between 2003 and 2014. “Given these facts and the compounding, regional and varied effects of climate change on extreme weather, a one-size-fits-all approach to resiliency, as outlined in the NOPR, is inappropriate and not adequate to the challenge,” they said.
House Energy Subcommittee Vice Chair Pete Olson (R-Texas) joined with ranking member Bobby Rush (D-Ill.) to say more time is needed to study the “remarkably complex issue.” They said it should be addressed “through existing proceedings at the federal and regional level rather than quickly moving to make a sweeping, top-down decision in the near term.”
“FERC — with bipartisan support from members of Congress and presidents — have worked for decades to improve these markets. Ultimately, this has given us markets that provide a reliable and resilient power system through open competition. This has also meant that risks are borne by investors in generating assets, not consumers or taxpayers. We continue to believe this is critically important,” they said.
Among those also registering support for the NOPR were the Interior Department, Southern Co. and AES (parent of Indianapolis Power & Light, Dayton Power and Light and AES Energy Storage).
Opponents Urge Time for Study
In contrast, the Electricity Consumers Resource Council and other industrial energy users said the NOPR would “overturn decades of precedent and suddenly determine the existing RTO/ISO tariffs are unjust and unreasonable.”
A broad coalition including the American Petroleum Institute, American Wind Energy Association, Conservation Law Foundation and Electric Power Supply Association reiterated its earlier comments, urging FERC to reject what they called an “abrupt and unjustified cost-based compensation mechanism.”
The National Association of State Utility Consumer Advocates, which had not filed initial comments, said acting on DOE’s demand for a final rule within 60 days would violate the Administrative Procedure Act by failing to provide the public with adequate notice or reasonable time to have meaningful input.
ISO-NE said the “very limited time” FERC allowed for reply comments did “not permit a comprehensive rebuttal to the efforts of the NOPR’s supporters to overcome the proposal’s unsound foundation.”
“However, in-depth analysis is not needed to understand why the proposal is both legally untenable and an unviable policy option,” the RTO said. “The breadth and depth of opposition to the NOPR among industry stakeholders and electricity consumers is striking in its own right.”
American Municipal Power also cited procedural concerns. “Several other commenters suggested that the commission adopt alternative proposals to modify the RTO energy market rules or take other actions that are beyond what was contemplated by the DOE proposal. The commission cannot lawfully accept such proposals as part of this rulemaking process.”
Former FERC Chairman Norman Bay made a similar point at the GTM U.S. Power and Renewables Summit in Austin, Texas, Tuesday.
“The timeline really amounts to a rocket docket. There’s no other way to describe it,” Bay said. “When you look at FERC Order 888, FERC spent a year on that particular order. In the normal course of events, it’s not uncommon to see a rulemaking take 12-15 months, or even longer than that,” Bay said.
AMP also agreed with many critics that the DOE proposal failed to prove existing RTO market rules are unjust and unreasonable. “The legal deficiencies coupled with the practical reality that the DOE proposal would not resolve the reliability concerns raised by the secretary but would impose significant new costs on customers should make this an easy call for the commission,” AMP said.
The Environmental Defense Fund urged FERC to “further enhance gas-electric coordination in a focused and targeted manner.”
“Electric generators were the smallest sector for natural gas demand in 1988, and they now are the largest,” EDF said. “But the natural gas regulatory framework has not kept pace with this new development.”
Next Steps
The commission has said it expects to take some action on the proposal within 60 days after its Oct. 10 publication in the Federal Register.
FERC will address the NOPR with a full complement of commissioners, thanks to the Senate’s Nov. 2 confirmation of Republican Kevin McIntyre and Democrat Richard Glick.
Tom Kleckner and Michael Kuser contributed to this article.
CenterPoint Energy executives Friday said the company is in “late-stage discussions” over its Enable Midstream Partners gas-gathering and processing joint venture but offered few details beyond that.
“Should these discussions not come to fruition, we will evaluate the sale of units in the public market place,” CenterPoint CEO Scott Prochazka said during a conference call with analysts.
Prochazka also said the Houston-based company “continues to believe Enable is well positioned for success.”
CenterPoint owns a 54.1% share of Enable. Oklahoma City’s OGE Energy holds a 25.7% limited-partnership interest and a 50% management interest.
In August, OGE accepted a right of first offer for CenterPoint’s shares. Any competing offer CenterPoint accepts for its interest would have to be at least 5% higher than OGE’s, CFO Bill Rogers said.
“This has been admittedly a long process,” Prochazka said. “As we come to the end of this, we will communicate the outcome, irrespective of what it is.”
CenterPoint reported quarterly earnings of $167 million ($0.38/share), down from $177 million ($0.41/share) a year ago. A Thomson Reuters survey of analysts had projected earnings of 39 cents/share.
The company said revenue for the quarter rose 11.1% to $2.10 billion, up from $1.89 billion for the same quarter last year.
Rogers said CenterPoint’s Hurricane Harvey restoration efforts have cost the company between $110 million and $120 million. A third of that will be covered by property insurance claims, with the rest recovered through capital mechanisms or regulatory assets in the company’s next rate case, he said.
| CenterPoint Energy
CenterPoint’s electric utility operations added 46,000 metered customers during the quarter, a 2% growth rate.
Wall Street reacted to CenterPoint’s announcement by driving down the company’s share price by 79 cents, to $28.96/share, when the market opened Friday. The stock recovered to $29.59/share by the market’s close.
OGE Q3 Earnings Unchanged from 2016
OGE on Thursday reported net income of $183 million ($0.92/share), compared to $184 million ($0.92/share) the same period a year ago. Third-quarter revenue was $717 million, down from $744 million the year before.
Analysts surveyed by Zacks Investment Research had projected earnings of 93 cents/share.
OGE’s Sean Trauschke | YouTube
OGE said its Oklahoma Gas & Electric subsidiary expects to file a rate case with the Oklahoma Corporation Commission by the end of year. The utility is seeking to recover $390 million in expenses to retrofit its Mustang power plant with seven 66-MW combined cycle gas turbines.
“It’s a much simpler case” than previous rate proceedings, CEO Sean Trauschke told analysts. “The plant will be finished and in service, so there’s no question about the cost.”
OG&E also expects to file another rate case with the OCC in 2018 to recover $542 million in environmental upgrades at its Muskogee plant.
OGE shares, which closed Wednesday at $36.75, were down to $35.97/share in Friday afternoon trading, a loss of 2.1%.
Pacific Gas and Electric earnings jumped 42% to $550 million during the third quarter ($1.07/share), boosted in large part by reduced expenses and realization of one-time income. Year-to-date profits for the utility have more than doubled to $1.5 billion, compared with $711 million last year.
The Pacific Gas & Electric building, San Francisco
Operating revenues for the electric side were $3.6 billion for the quarter, out of total revenues of about $4.5 billion.
“The quarter-over-quarter increase reflects lower expenses primarily due to the absence of disallowed charges related to the San Bruno penalty decision, which impacted the third quarter of 2016, and also due to insurance proceeds in the third quarter of 2017 related to the court-approved settlement of the shareholder derivative suit, with no similar amount in 2016,” PG&E said during an earnings call Thursday.
During the first nine months of the year, the utility incurred $71 million in costs associated with in fines and penalties, including disallowed expenses of $32 million, related to an April 2015 decision by the California Public Utilities Commission regarding the San Bruno pipeline explosion.
PG&E CEO Geisha Williams also discussed the wildfires that blazed across the state in the third quarter, saying “we also remain focused on continued investment in vital infrastructure and technology to increase the resilience and the sustainability of California’s energy economy for the future.”
The utility restored service to 360,000 electric customers and 42,000 gas customers during the disasters, saying it is aiding the PUC and California Department of Forestry and Fire Protection in their investigations.
PG&E updated its 2017 guidance range to $3.36 to $3.56/share because of the reinstatement of the company’s liability insurance following the wildfires and an increase in the expected third-party claims associated with the 2015 Butte fire, partially offset by insurance recoveries.
PG&E’s Humboldt Bay nuclear plant, which is being decommissioned
More than 12 victims of the recent wildfires have filed suit against PG&E for this season’s blazes, which claimed 43 lives and burned thousands of homes and commercial buildings. The company told the Securities and Exchange Commission on Oct. 13 that “the causes of these fires are being investigated by the California Department of Forestry and Fire Protection (Cal Fire), including the possible role of power lines and other facilities of” PG&E. The company said it is unknown whether it will have any liability, but it has $800 million in liability insurance for potential losses from the fires.
Arizona Public Service parent company Pinnacle West Capital earned $276 million ($2.46/share) in the third quarter, compared with $263 million during the same period in 2016.
APS’ Palo Verde nuclear plant
“Our service territory experienced solid customer growth of 1.9% as new customers moved to Arizona for job opportunities and an improved quality of life, our employees continued to demonstrate superior customer service and operational performance, and we successfully settled our rate review,” Pinnacle CEO Donald Brandt said.
The Arizona Corporation Commission allowed APS to raise its rates for the first time in five years. The company said the increase will allow it to invest in cleaner infrastructure and provide customers with new rate options.
APS’ Navajo Generating Station coal-fired power plant
Customer growth lifted profits by 2 cents/share compared to a year earlier despite milder temperatures. Pinnacle raised its earnings guidance to $4.25 to $4.45/share for 2017 and $4.15 to $4.30/share for 2018.
APS’ rate base is expected to grow about 6% annually, to a projected $8.2 billion in 2019.
The few supporters of the U.S. Department of Energy’s proposal to FERC have promoted an insane rush to judgment in the absence of anything remotely resembling an emergency — or even a problem.[1]
In the reckless stampede imposed on the electric industry, these clunker owners have shot themselves in the foot. Twice.
First, they have largely accepted — and even refined — the provision of the DOE proposal that makes their nuclear units categorically ineligible for any subsidy.
Second, they have invoked the risk of electromagnetic pulses and geomagnetic disturbances as a basis for the DOE proposal when their coal and nuclear units are the most vulnerable to such risk.
Clunker Nuclear Units are Ineligible for Subsidies
The DOE proposal is amorphous on almost everything, but it is crystal clear that an eligible resource must be able to provide “ancillary reliability services,” specifically including “frequency services.”[2]
FirstEnergy suggested refining “frequency services” to “frequency response services” in order to “reflect terminology typically used by RTOs/ISOs.”[3]
Thank you, FirstEnergy, for straightening the deckchairs on the Titanic.
Because here’s the thing: Nuclear units can’t and don’t provide frequency response. The Nuclear Energy Institute, on behalf of its members like FirstEnergy, Exelon and Public Service Enterprise Group, was vehement in comments to FERC last year that nuclear units had no or limited frequency response capability, and for those few nuclear units that might be able to provide limited frequency response, the Nuclear Regulatory Commission doesn’t allow it.[4]
In reliance on those nuclear industry representations, FERC proposed to exempt all nuclear power plants from providing frequency response.[5] You can’t eat your cake and have it too.
By the way, in the significant frequency event in the Eastern Interconnection studied by NERC, nuclear units actually provided a negative response of 12 MW.[6] In other words, they made the reliability problem worse. No participation trophy for them.
Another required service is “operating reserves.” This means a generating unit must change output on command to help cover the loss of another generator on the system. Nuclear units don’t provide this service because they operate at 100% capacity (so no “headroom”), and because changes in output present unique safety problems, as described to FERC at a technical conference in 2010 by Jack Grobe, then deputy director of NRC’s Office of Nuclear Reactor Regulation, now executive director at Exelon Nuclear (emphasis added):[7]
“Power is not infrequently adjusted a few megawatts to deal with equipment issues. For example testing of valves, changing of rod patterns in the core, but those are just a few megawatts. More significant power changes introduce things like what Bruce [Mallett, NRC deputy executive director for reactor and preparedness programs,] was saying; those require a lot of equipment manipulations and it introduces the potential for human factors concerns. Human errors, things of that nature.
“From a safety perspective, it also introduces changes in the dynamics of the core, because the neutrons that create fission also burn or destroy poisons in the core and the fission of the uranium nucleus creates poisons. There is a unique balance that goes back and forth when you make power changes to building in of poisons and burning out of poisons and different things of that nature. So, it changes the dynamics on how the fuel burns and this affects the efficiency in the fuel economy for the operator. Not a concern of ours, but it creates instabilities in the way, not unsafe instabilities, but just changes in the way the core behaves. So, all of those things introduce the opportunity for perturbations to the safety of the core from the standpoint of the way the operators have to respond.”
Translation: Any nuclear unit that would vary output to provide operating reserves is taking a walk on the wild side. Ain’t gonna happen.
Bottom line: DOE specified two “ancillary reliability services” that an eligible resource must provide, and nuclear units can’t and won’t provide them.
Coal, Nuclear Most Vulnerable to EMP/GMD
Exelon invokes EMP/GMD risk in support of the DOE proposal.[8]
Here’s the thing: DOE’s own Oak Ridge National Laboratory identified coal and nuclear units as the most vulnerable to EMP risk.[9] Coal and nuclear cooling tower motors have a particular vulnerability. And nuclear units have additional vulnerability due to “the extremely complex reactor control circuitry in control rooms.”
Harris Nuclear Plant’s cooling tower | Duke University
So if EMP/GMD risk is important, that favors maximizing natural gas and renewable resources and minimizing coal and nuclear units. It’s the diametric opposite of subsidizing uneconomic, unreliable coal and nuclear clunkers.
Isn’t it Ironic?
In their reckless haste, the clunker owners overlooked the fact that their own nuclear units aren’t eligible and that the EMP/GMD risk they invoked is greatest for their own coal and nuclear units.
Isn’t it ironic, don’t you think?
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.
My last column showed that the chance of a winter generation deficiency in PJM is much less than one in 5,000, and were that to occur, the chance of the deficiency being due to a fuel supply emergency is remote. And if these two remote circumstances were to coincide, PJM would still have reliability tools to avoid customer impact. There is no beef. ↑
Proposed 18 C.F.R. §35.28(g)(10)(i): “An eligible grid reliability and resiliency resource is any resource that: …(B) Is able to provide essential energy and ancillary reliability services, including but not limited to voltage support, frequency services, operating reserves, and reactive power;” ↑
https://elibrary-backup.ferc.gov/idmws/common/opennat.asp?fileID=14213680. “… nuclear generating units have no or limited response to interconnection frequency changes.” (page 3). “In summary, even if a nuclear unit does have the capability to provide a limited response (typically a maximum of 1% reactor thermal power) to a significant frequency deviation; the NRC licensed operators are not authorized to operate the unit above the maximum power level as specified in the NRC issued Operating License and they are required to take immediate actions to restore reactor power to less than 100.0% Reactor Thermal Power in the event of any transient.” (page 4). ↑
LITTLE ROCK, Ark. — SPP’s Board of Directors last week approved a cleanup of Tariff language that may have put much of the RTO’s troublesome Z2 process in the rearview mirror.
During the board and Members Committee’s quarterly meeting Oct. 31, stakeholders approved an option put forward by Kansas City Power & Light, altering a previously approved revision request (RTWG-RR244) to align with the original intent of the task force producing the revision.
The original measure passed the Markets and Operations Policy Committee earlier in October with minimal discussion and only two abstaining votes. One of those was cast by KCP&L’s Denise Buffington, who chaired the task force that worked to simplify Attachment Z2 of SPP’s Tariff, in which financial credits and obligations are assigned for sponsored transmission upgrades.
In July, MOPC and the board accepted the Z2 Task Force’s recommendations to eliminate credits for non-capacity upgrades, such as substation facilities, and for short-term transmission service of less than a year. (See “Z2, Two Other Task Forces Expire,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)
However, the Regional Tariff Working Group’s language in RR241 would have cut off those credits for existing service agreements upon the effective date of the Tariff revision, rather than let them expire when the service did.
Buffington said the first time she realized there was an issue with the Tariff language was during the MOPC meeting, and she offered two options to correct the oversight. “Option 1” ensured that short-term firm and non-firm point-to-point transmission service granted prior to the effective date would “continue to be used to pay revenue credits … for the duration of term of that service.”
“I don’t believe the RTWG implemented the intent of the task force,” Buffington said. “We specifically talked about short-term reservations and when credits would end. Our intent was that if reservations were granted, they would continue to receive credits for the life of that service.”
Asked how the RTWG’s language had slipped by unnoticed, Oklahoma Gas & Electric’s Greg McAuley told the board and committee, “It was a matter of not enough of this discussion taking place, or not enough time when this came about.”
SPP’s Charles Locke said the task force’s proposed language was “administratively more difficult.”
“Staff does have a preference for the MOPC recommendation, because it can be implemented sooner,” Locke said. “It reduces the risk resettlements will happen. Short-term credit flows create uncertainty. Not only are there additional administrative challenges for staff, but also settlements and for member companies.”
“I hear there is some risk today,” Buffington countered, “but I don’t hear concrete reasons you can’t implement one of these options.”
“There’s an argument to be made that this is retroactive ratemaking,” said NextEra Energy Resources’ Aundrea Williams, referring to the potential premature end to transmission service agreements.
Locke eventually offered that all three options before the board would fulfill the Z2 task force’s recommendation.
“All three could also be filed at FERC and accepted, because they’re prospective in nature,” he said. “In terms of Option 1, it’s essentially a staggered implementation. Assuming a Feb. 1 implementation date, [short-term] reservations would run for various periods of times. Eleven months might run into the fall of 2018.”
“We’ve done a lot of work here, and good things, with reaching an agreement on non-capacity upgrades,” said MOPC Chair Paul Malone, who also served on the Z2 task force. He reminded stakeholders that non-firm service only accounts for about 2% of the credits.
“Let’s do the right thing here and avoid potential trips at FERC,” Malone said. “Let’s not have this one be where a filing gets thrown back in our face.”
In the end, the board accepted the Members Committee’s unanimous approval of KCP&L’s first option.
“There’s been a lot of discussion about the potential for a burdensome administrative effort to do this,” Buffington said. “But now, we’re hearing that maybe it’s not so difficult.”
SPP to Seek FERC Input on Behind-the-Meter Load
With members unable to reach agreement on how to report behind-the-meter network load, the board directed staff to reach out to FERC for clarity, in the hopes of settling the matter during SPP’s January membership meetings.
The RTWG ended several years of work in early October when it presented new Tariff language to the MOPC. The measure would have established a 1-MW threshold for BTM output at a discrete delivery point and in front of the retail customer’s meter, but it drew only 54.6% of votes in favor. (See “Stakeholders Unable to Reach Consensus on Network Load,” SPP Markets and Operations Policy Committee Briefs.)
Southwestern Public Service appealed the rejection to the board, saying “consistent reporting of network load among all entities … is critical to ensuring that the costs of network service are fairly distributed to SPP network service customers.”
SPS said without the consistent reporting, some SPP customers would be subsidizing network service used by other customers.
“This issue has been circling the airport for the last four years. We feel like it’s time we resolve this issue,” said SPS President David Hudson. The company has been following FERC Order 890 in reporting all BTM load, he said.
“What we’re finding out is more and more people are not reporting these loads,” Hudson said. “We want consistency that everyone is receiving the same billing determinants.”
“Order 890 is relevant, but subsequent orders that directly and indirectly addressed this order said that some exclusions are relevant and can be made,” McAuley, making it clear he is not a lawyer, said in responding to the concerns of SPS and others. OG&E makes that exclusion and does not report BTM load.
“The overarching idea is that if a generator does not impact the transmission system, it should not be included for calculating that load,” McAuley said.
“People are admitting they’re inconsistent,” said Bill Grant, SPS regional vice president of regulatory and strategic planning. “It’s been four years. When are we going to make a decision?”
Board Chair Jim Eckelberger brought the discussion to a close when he asked staff to gather definitions from FERC to gain a better understanding of the problem. General Counsel Paul Suskie said staff are already working to lay out the commission’s explanations of what is and what isn’t net metering.
“Let’s make sure that at the January MOPC we have an answer we can work with,” Eckelberger said. “Let’s ensure everyone understands what the rule is.”
Director Larry Altenbaumer added that the board should make “an absolute commitment … to take action in January.”
That seemed to satisfy the members. Said Westar Energy’s Kelly Harrison: “We may not like it, but at least they make a decision.”
Brown Looks Back to Move Forward
SPP CEO Nick Brown told the board and committee that in drafting a speech for a member company’s annual meeting, he looked back at 2007 and future predictions for the industry.
“Quite clearly” no one would have predicted what has come to pass since, he said.
“We passed the 10-year view for wind energy in a year and a half,” Brown said. “Transmission expansion we got horribly wrong. Gas prices were horribly wrong. Even in the most perverse, extreme scenario, no one would have contemplated the natural gas prices we’re seeing today.”
Brown recalled gas prices were at $7/MMBtu, peaking above $13, and then settling into the $2 to $3 range.
“None of us saw that coming,” he said.
Nor did the RTO anticipate investing $10 billion in transmission within the footprint, consolidating its various balancing authorities into one, or the advent of financial transmission rights.
Still, Brown said, “I would argue we’ve been pretty strategic in what we’ve accomplished.”
Brown took advantage of the opportunity to let the board and stakeholders know he had ordered each director and committee representative copies of Craig Roach’s recently released book, “Simply Electrifying: The Technology that Transformed the World, from Benjamin Franklin to Elon Musk.”
Roach is a nationally recognized expert on electricity, and the founder and president of electricity consulting firm Boston Pacific. Last year it joined Bates White’s energy practice, for which Roach collaborated on SPP’s annual forward-looking report.
Brown also noted that SPP will on Dec. 19 mark 20 years as a reliability coordinator within its footprint. The RTO plans to celebrate the milestone on or around that date.
Finance Committee Proposing 1-Cent Increase in Admin Fee
Altenbaumer, chair of the Finance Committee, said he will be proposing a 1-cent increase in the system administrative fee at December’s board meeting, when SPP’s budget is typically voted on.
The director said the committee has suggested an increase to 42.9 cents/kWh, up from the current 41.9 cents, because of a systemwide loss of load and SPP’s commitment to absorb former staffers of the soon-to-be-dissolved SPP Regional Entity (RE), he said.
Altenbaumer also said the committee is taking advantage of Mountain West Transmission Group’s integration to possibly restructure the manner in which SPP is paid for its expenses. Any changes would be coordinated with the integration process, he said.
Directors, Members Committee, RE Trustee Elections
The board re-elected three directors and elected six Members Committee representatives to three-year terms, beginning Jan. 1, during the annual meeting of members.
Elected to new board terms were Altenbaumer, Joshua W. Martin III and Bruce Scherr. Martin has served on the board since 2003, Altenbaumer since 2005 and Scherr since 2016.
Arkansas Electric Cooperative’s Duane Highley, SPS’ Hudson, Oklahoma Municipal Power Authority’s David Osburn and NextEra’s Williams were all re-elected to the committee. Elected for the first time to the committee were McAuley and Omaha Public Power District’s (OPPD) Joe Lang.
Lang replaces OPPD’s Jon Hansen, who is retiring after 34 years in the industry.
Gerry Burrows was re-elected to the RE’s board of trustees. The RE will be dissolved by December 2018.
Revision Request to Address Potential Gaming Passes
The board approved a measure targeting potential gaming related to the regulation deployment adjustment settlements charge type. MWG-RR243 eliminates market participants’ ability to use energy offers to game incentive payments by using the lesser of the as-dispatched energy offer curve and mitigated energy offer curve for the regulation-up adjustment, and the greater of the as-dispatched offer curve and mitigated energy offer curve for the regulation-down adjustment.
Dogwood Energy’s Rob Janssen, who abstained during the MOPC’s vote two weeks earlier, said he intended to vote for the change, as it was a “good enough answer” to a “problem in need of a solution.”
Addressing member concerns about the measure’s $119,220 implementation cost and suggestions that the Market Monitoring Unit simply monitor the potential gaming, MMU Executive Director Keith Collins noted manipulation of regulation-down offers has cost the market about $1 million in recent years.
“If only it were that simple,” Collins said. “What can happen at times is there’s usually a dialogue, there’s an observation… Is this potentially an issue, or is it not? That cost can outweigh the concerns we’re having here of the implementation costs or an inefficient solution.”
Westar was the only member to oppose RR243, while two others abstained.
The board’s consent agenda included three additional RRs:
MWG-RR231: Removes locally committed resources from economic mitigation tests and creates a 10% cap for resources committed for local reliability. Addresses the practice among some resources of “self-mitigating” to pass the conduct threshold test and avoid possible mitigation by submitting competitive energy offers 10% above the mitigated offer.
ORWG-RR240: Removes Section 7 of the SPP Operating Criteria and creates a standalone SPP Reserve Sharing Group Operating Process for BAL-002-2’s annual maintenance process, which becomes effective Jan. 1.
RTWG-RR238: Addresses the financial exposure to SPP and its market participants stemming from a defaulting transmission customer avoiding responsibility for the full amount owed for the full term of a service agreement. The change also restricts the ability of SPP, transmission owners and transmission customers from recovering attorney’s fees related to performance of a service agreement, and clarifies that each party to an arbitration under the Tariff is responsible for its own fees.
VALLEY FORGE, Pa. — PJM and its Independent Market Monitor provided updates to their capacity market redesign proposals at last week’s meeting of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF), but the discussion was dominated by the question of when the group should recommend any rule changes.
Proponents for load — including American Municipal Power, Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition (ICC) and the PJM Public Power Coalition (PPC), the Organization of PJM States and the Consumer Advocates of the PJM States (CAPS) — argued that the decision should be delayed until after FERC responds to the Department of Energy’s Notice of Proposed Rulemaking for coal and nuclear price supports. The commission has said it expects to take some action on the proposal within 60 days after its Oct. 10 publication in the Federal Register.
Generators urged staying on the task force’s current timeline of having a proposal selected to file with FERC by the end of the year. “By putting things off, we just slow down the process,” Calpine’s David “Scarp” Scarpignato said.
Monitor Joe Bowring called for stakeholders to take the lead on how FERC responds to the NOPR.
“What you say does affect the process,” he said. “I would urge you all not to think of yourselves as passive consumers of what FERC is doing. They’re looking for guidance as well.”
Load representatives, however, said they didn’t have enough information to make an informed choice.
“Boy, I don’t have anything among any of these proposals that I can say, ‘This is what’s going to be best for the market and my customers’ future,’” said Carl Johnson, who represents the PPC.
Joe DeLosa, of the Delaware Public Service Commission, said there has been some difficulty in evaluating proposals. “We feel the time is not appropriate to move forward with proposals,” he said.
Morris Schreim, of the Maryland Public Service Commission, asked about a commitment he said PJM made to perform an analysis of the most popular proposals. At a meeting in August, staff agreed to research possible solutions to several stakeholder concerns, including a request from ODEC’s Adrien Ford to substitute data from recent Base Residual Auctions into PJM’s model of the proposals. (See PJM Stakeholders Begin Defining Capacity Design Needs.)
PJM’s Adam Keech responded to Schreim that he remembers another meeting where staff “pretty clearly” said they would not be performing modeling.
RTO officials acknowledged the concerns of load but remained focused on the current timeline.
“I believe it’s important for this group to keep working forward,” PJM’s Suzanne Daugherty said.
PJM Revises Reference Price
PJM revised the reference price in its proposal for undefined subsidies. Previously, it was calculated using a formula for a competitive offer: the net cost of new entry multiplied by the expected average balancing ratio for the delivery year. The RTO has revised it to a “capacity repricing value” that is based on resource type and whether it’s new or existing. That value is used to resort the generation offers in the second, price-setting stage of PJM’s proposal.
The RTO presented its methodology for calculating the default values along with example values for delivery year 2021/22 measured in gross dollars. An existing combined cycle gas turbine’s value would be $84 per ICAP MW-day, while a new unit would be $501. Onshore wind would be $65 and $998, respectively.
“What we’re trying to do is determine what the market price should be for that year,” PJM’s Rich Brown explained.
Stakeholders asked Brown to provide a comparison of how reference prices change under PJM’s previous proposal and the new “capacity repricing values.”
Bowring didn’t need any comparisons.
“This is entirely inconsistent with the Capacity Performance paradigm,” he said.
The Monitor revised its proposal to expand one of the exemptions to its extended minimum offer price rule (MOPR) proposal. The renewable portfolio standard exemption would be extended to all competitive, non-discriminatory, state-mandated programs and not just competitive auctions. The IMM is also planning to adjust its public power exemption to allow supply to be “slightly” greater than 105% of demand for a year “to recognize that investment can be lumpy,” Bowring said.
Several load proponents, including Ford, AMP’s Steve Lieberman and Susan Bruce, representing the PJM ICC, thanked Bowring for his willingness to adjust his proposal.
“We don’t think repricing is the right answer,” Ford said, acknowledging that ODEC’s proposal, which has been retracted, included repricing. “We’re really appreciative, Joe, that you’re listening to some of the concerns expressed here in the CCPPSTF and finding ways to modify what we think is a fairly pure market proposal as opposed to an administrative, two-stage approach.”
“Certainly, we continue to believe that the time is not appropriate to move forward, especially with the NOPR out there, but we appreciate the efforts that have been made to try to frame the issue,” Bruce said. “I am not at all suggesting that the time is never. … We live in a time of more uncertainty than I’ve seen. … We’re going to see some guidance from FERC soon, and I think that is going to be an important touchstone.”
Greg Poulos, the executive director of CAPS, said some state advocates are questioning why stakeholders are “all of a sudden” focused on revising the capacity market after nuclear units in one PJM state — Illinois — received price support, particularly when they believe there will not be any new subsidies for generators. He said there is “growing support” among the advocates for the Monitor’s revisions.
“It’s definitely getting more favor from the advocate groups,” he said.
The remaining proposals — from NRG Energy, LS Power, Exelon, AMP, Northern Virginia Electric Cooperative and the Natural Resources Defense Council’s Sustainable FERC Project — had no new revisions.
Poulos expressed advocates’ concerns about “gaming” the repricing structures, and asked representatives from LS and NRG, who have also submitted repricing proposals, whether they have examined how their proposals prevent gaming and how their protections compare to other repricing proposals. The representatives said they have not noticed or been alerted to any concerns.
“We don’t see a meaningful distinction between all the repricing proposals,” Bowring said. “We think they’re all subject to the kinds of issues that were raised by [Poulos].”
FERC may consider additional changes to its hydropower licensing rules following a review prompted by President Trump’s March 2017 executive order to eliminate burdens on domestic power production.
Executive Order 13783, “Promoting Energy Independence and Economic Growth,” required executive branch officials to review their regulations, orders and policies and eliminate those that “unduly burden the development of domestic energy resources.”
On Nov. 1, FERC published in the Federal Register a 30-page report in response, saying it had found several potential changes involving its hydropower rules that the commission may consider. Commission staff emphasized that, as an independent agency, it was not required to respond to the order but was doing so voluntarily.
The report said “the vast majority of agency actions relating to the commission’s hydropower program do not present a material burden.”
But it said the commission “could consider” revising its regulations to:
Make optional the integrated licensing process (ILP), which is currently the default — requiring applicants to justify the use of the traditional licensing process or the alternative licensing process;
Make optional the requirement to submit a draft license application or preliminary licensing proposal before submitting a final license application as part of the prefiling process;
Reducing comment and filing deadlines to save three months in the three- to three-and-a-half-year process for obtaining an integrated license;
Increasing the threshold — currently 5 MW — for eligibility for the “simplified and expeditious licensing procedure for small hydroelectric power projects” under the Public Utility Regulatory Policies Act;
Removing the requirement that facilities eligible for license exemptions under PURPA Section 405 install or increase the capacity of their facilities;
“Explicitly” allow applicants for small hydropower exemptions to convert their exemption applications to a license application if the exemption is rejected; and
Allow hydro operators whose license applications are rejected to resubmit their applications once the deficiencies are corrected.
Next Steps up to Commission
FERC spokeswoman Mary O’Driscoll emphasized that the response is a FERC staff report. “The commission itself will determine what steps to take on any and all matters related to this,” she said in an email. “We cannot predict, nor can we surmise, what the commission will do in the future.”
The response to the executive order also says the commission “currently is considering comments” on its policies on the length of hydropower licenses, an apparent reference to the responses to its 2016 Notice of Proposed Rulemaking (RM17-4).
Kerr Dam in Montana
O’Driscoll explained that the staff response was due Sept. 27, before the commission’s Oct. 19 meeting, at which it approved a policy statement setting a 40-year default license term. The commission said the change will reduce administrative costs and encourage dam owners to upgrade capacity and make environmental or recreational investments (PL17-3). (See FERC Sets 40-Year Term for Hydro Licenses.)
Prefiling Requirement for LNG Terminals
Commission staff also reviewed but found no rules to recommend changing regarding LNG terminals; natural gas pipeline and storage facility siting; generator interconnection policies; and electric capacity markets in PJM, ISO-NE and NYISO.
For example, staff examined the prefiling process for LNG terminals and related facilities but ultimately decided “there is no need for the commission to consider any revision.”
Commission regulations require applicants to use its prefiling process for at least 180 days before filing an application. Staff said that although the Natural Gas Act only requires prefilings for terminals and not “related” facilities, gas pipelines and the terminals they serve need to be evaluated together to avoid segmentation under the National Environmental Policy Act.
“Further, the prefiling process allows stakeholders to become involved in the overall project at an early stage, and applicants can benefit from stakeholders’ early identification and resolution of issues that may overlap with the LNG terminal. Without using the prefiling process for related jurisdictional natural gas facilities, delays could occur during the application review, when issues are first identified and need resolution,” staff said. “Thus, although this regulation may result in delays or additional costs to the applicant early on in a project’s development, its overall result is a more timely application review.”
