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.”
The CEOs for three of the largest companies that stand to gain from proposed price supports for nuclear and coal generators used their third-quarter earnings calls last week to praise FERC, the Department of Energy, PJM and states for their attention to the issue.
Exelon’s Chris Crane, Public Service Enterprise Group’s Ralph Izzo and Dominion Energy’s Thomas F. Farrell II all made a point to thank the RTO, states or federal agencies who have made — or are considering — changes to funnel additional money to the generators, which the companies argue are critical to the grid but undervalued in markets.
And they had good reason to. Crane said “each dollar [per] megawatt-hour of distortion caused by a flawed market design” costs the company $135 million per year. Izzo said each dollar change in per-megawatt-hour revenue from PJM is worth $55 million pre-tax to his company.
“We commend [Energy Secretary Rick Perry] for focusing attention on the need to reform the energy markets, and ensure that our customers continue to benefit from the resilient system,” Crane said. “Between these efforts and state initiatives, we’re optimistic about the path to preserve nuclear power plants. … We are confident that the FERC actions around resiliency will facilitate needed power price reforms in PJM that will fairly compensate our generating assets.”
The DOE’s Notice of Proposed Rulemaking “is aimed at protecting our customers from outages resulting from manmade and natural interruptions on the gas system by preserving resilient generation sources, including nuclear,” he said.
PSEG is “on track … to reduce the all-in cost per megawatt-hour of its nuclear operations by 10% from the average cost experienced during the prior three years,” Izzo said. “But energy prices influenced by the availability of natural gas have declined by a greater degree during this time frame.
“We believe that the DOE NOPR is necessary. … We recommend that measures adopted in response to the DOE NOPR should be viewed as an interim [solution] until effective mechanisms can be developed that recognize these attributes in the market,” he said. “State action also remains critical to prevent the loss of these units. We believe state action can be done [in a] way that both maintains the integrity of the wholesale market and serves as a bridge until a regional [or] federal solution is in place.”
State ZEC Programs
Farrell
Farrell didn’t want to speculate on the outcome of the NOPR, but said “Connecticut certainly hasn’t been willing to depend on it.” He said he expects Connecticut lawmakers to follow Illinois and New York in establishing a zero-emission credit program to support nuclear units.
Last week, Gov. Dannel Malloy signed a bill that could allow Dominion’s Millstone nuclear plant in Waterford, Conn., to compete in a state-sponsored solicitation for zero-carbon electricity if officials conclude it is in the best interest of ratepayers. Malloy, however, said he believes the plant is profitable and does not need a subsidy.
“Dominion Energy thanks the general assembly for giving Millstone this opportunity and is grateful to the Malloy administration for his work in negotiating the current form of the legislation,” Farrell said.
“We weren’t surprised” by approval of the legislation, he added. “We’ve been working on it for two years and been deeply involved in it for that period of time.”
Joe Dominguez, Exelon’s vice president of governmental and regulatory affairs and public policy, also praised the Connecticut legislation and said that his lobbying efforts aren’t done.
“We have been [in] very productive discussions both in Pennsylvania and New Jersey. We’ll continue to do that,” he said.
He said that the ZEC programs are designed to decrease if energy-market reforms happen, so “it will not be a double-dip here.”
Izzo said PSEG is lobbying as well.
“Depending on what happens at the federal level, there remains the opportunity for New Jersey to recognize certain attributes that perhaps are not explicitly identified at the federal level,” he said. “We are just in a series of conversations with people right now. We are just making sure they understand what our nuclear plants mean to New Jersey.”
FERC Action
Izzo and Crane agreed FERC should order PJM to revise its price formation methodology, a move Izzo called a “no brainer” and “long overdue.” Crane anticipated changes by as early as mid-2018.
Defining “resiliency” has been an ongoing debate, but Dominguez said PJM’s Capacity Performance design makes the discussion quantitative.
“We were able to value the cost of incremental reliability associated with dual fuel, so if the design basis ultimately ends up being we need 90 days of fuel, we have a mathematical way of calculating what’s the market solution to get dual-fuel resources to 90 days of fuel with it,” he said. “That would probably be $8 or $10/MWh in terms of doing that based on the cost we saw in CP.”
A rule from FERC that boosted power prices could also leave smaller retail competitors who have been “aggressive” in their pricing vulnerable to acquisitions by large, integrated energy companies like Exelon, Crane said.
“Any time we’ve seen a volatility event … we’ve had opportunities to acquire companies in that type of environment,” Crane said.
Izzo said he was wary of projections that rules on price formation will increase PJM energy prices by $2 to $4/MWh, saying it ignores other factors that can have an impact.
“What [is the impact] of pipelines that may change the basis differential of gas in Western PJM versus Eastern PJM? What [is the impact of] future carbon constraints that may or may not be part of a subsequent administration in Washington?” he said. “Some people on this call may want to go see their children in their Halloween parades; otherwise I would list a thousand other factors that should go into people’s thought process before making those kind of investment decisions.”
Earnings
Crane said the Illinois Power Authority’s decision last month to delay the finalization of the procurement of the ZEC contracts from December 2017 to January 2018 will shift 9 cents of earnings per share from 2017 to 2018.
Exelon earned $824 million ($0.85/share) in the third quarter, missing expectations by 1 cent but improving on the 53 cents/share earned in the same quarter a year ago. Revenue of $8.77 billion beat expectations by $90 million but was down from $9 billion a year ago. Operating earnings were 85 cents/share, compared to 91 cents/share for the third quarter of 2016.
While Exelon hasn’t escaped the industry’s cyclical nature, “we’ve gained greater flexibility with programs like the ZEC,” Crane said.
Dominion posted operating earnings of $672 million ($1.04/share) for the third quarter of 2017, which beat expectations by 2 cents but was down from $716 million ($1.14/share) for the same period in 2016. Revenue of $3.18 billion missed expectations by $110 million but was up from $3.13 billion in the third quarter of 2016.
PSEG reported third-quarter operating earnings of $417 million ($0.82/share), which missed estimates by 2 cents and was down from $444 million ($0.88/share) a year ago.
Seeking Alpha provided the earnings calls transcripts for this article.
PJM’s announcement on Thursday of plans to recommend more than $400 million in transmission upgrades — just weeks after the RTO’s Board of Managers authorized $1 billion in spending — sparked pushback from American Municipal Power, which said the RTO ignored questions about the effectiveness of several of the projects.
Staff plan to recommend adding the projects to PJM’s Regional Transmission Expansion Plan at the board’s Dec. 4 meeting.
AMP’s Ryan Dolan questioned PJM’s analysis of several of the reliability projects, arguing that the proposed solutions fail to address all issues at the nodes in question and will necessitate additional construction in the future. He was displeased that PJM plans to recommend the projects even though, he said, concerns were raised about their effectiveness from a “holistic planning” perspective at a sub-regional RTEP discussion the previous day.
“For some of these projects, basically … [PJM is] planning on making these recommendations no matter what comments were provided,” Dolan said. “I think it would be useful to give time between when we make recommendations to when the last review of a project is to ensure any of the comments … that were brought up … can actually be accounted for.”
PJM’s Mark Sims responded that all information underlying the RTO’s recommendation has been available throughout the planning process and that recommendations can change as additional information is added to the analysis.
“We’ve been transparent with all the steps along the way,” he said.
The $400 million in additional projects will be recommended as the result of a reliability analysis for the 2021/22 delivery year, Sims said. They include eight projects from the first RTEP proposal window for 2017, along with 13 projects that were previously identified.
The recommendations also include one market efficiency project proposed by American Electric Power to address a thermal constraint on the Tanners Creek-Dearborn 345-kV circuit. PJM’s Nick Dumitriu explained that AEP’s $600,000 solution would upgrade equipment at the Tanners Creek station, removing price separation in the Duke Energy Ohio/Kentucky (DEOK) locational deliverability area in the 2020/21 Base Residual Auction Capacity Emergency Transfer Limit (CETL) study.
PJM rejected two other proposals for the same constraint that estimated costs at $4.9 million and $12.7 million.
RTO staff confirmed the upgrades will be included in the model for the 2021/22 BRA.
AMP has become increasingly critical of transmission spending in PJM. In September, the company released a report showing that more than half of the $24.3 billion in transmission spending in the RTO since 2012 were supplemental projects by transmission owners and were not needed to comply with RTO or federal reliability requirements. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
CARMEL, Ind. — MISO expects to easily manage this winter’s anticipated 103.4 GW of peak demand with an estimated 142 GW of available capacity, stakeholders recently learned during a trio of meetings focusing on winter preparedness.
“We certainly can’t be complacent. … In winter, just like in every season, we have to be ready for anything thrown at us, but we’re prepared,” MISO Executive Vice President of Operations Richard Doying said during a Nov. 6 winter readiness workshop.
Northern Indiana Public Service Co. crews make repairs after a late December storm in 2015 | NIPSCO
Using National Oceanic and Atmospheric Administration projections, MISO predicts this winter will be warmer than normal in its Central and South regions, while temperatures in the North region will be normal to below normal.
Darius Monson of MISO’s resource adequacy coordination group said the RTO’s winter reserve margin is expected to vary between 28.3 and 37.3% without factoring in outages.
“That’s a fairly good position to be in,” Doying said.
However, the reserve margin could range from 6.7 to 19.3% after taking possible outages into account, Monson said, compared with this year’s footprint-wide 15.8% planning reserve margin requirement. The RTO used historical outage data to predict winter outage levels anywhere from the more probable 23.3 GW, to 28.7 GW in a high load, extreme outage scenario. MISO might need to rely on behind-the-meter generation and demand response resources to meet peak demand under that scenario, Monson said.
The RTO does not predict any major constraints or thermal and voltage issues during the winter.
Engineer Katherine Hulet said MISO did not uncover any potential issues through its biannual Coordinated Seasonal Assessment. The study evaluates a variety of stressed conditions across the MISO footprint and identifies potential limitations and issues on the system for the upcoming winter.
Hulet said the RTO studied possible transmission contingencies, potential transfer contingencies, voltage stability and possible phase angle differences, but found no cause for concern.
“It really looks like MISO’s in pretty good shape. Not only are there capacity resources, but the transmission is in a position do well,” Reliability Subcommittee Chair Tony Jankowski said during a Nov. 2 conference call.
Jankowski asked if MISO is considering performing seasonal studies for shoulder periods. Hulet said seasonal studies will continue to be limited to summer and winter.
Jankowski urged operators to ensure all generators are in good repair. “Eventually that arctic air will make it into our footprint,” he warned.
Doying also said MISO is well-positioned for winter reliance on natural gas.
“We have access to just about all pipeline interconnections. Actually, most of the gas storage in the country is located within MISO,” Doying said during an Oct. 31 Markets Committee of the Board of Directors conference call. The RTO expects gas storage inventories nationwide to peak at 3.8 Tcf this winter, slightly below the five-year average, and prices to continue hovering around $3/MMBtu into winter.
Independent Market Monitor David Patton said MISO’s proximity to gas storage makes it easier to quickly ensure fuel supplies if a pipeline goes down, whereas the New England region doesn’t have such supply backups, requiring more Northeast generators to have dual-fuel capability.
“We’re ready until the next polar vortex presents a whole new realm of challenges,” MISO Chairman Paul Bonavia remarked jokingly.
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.
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.
