Consolidated Edison will stop using the “PSEG wheel” next April, following through on a promise it made late last year in a dispute with PJM over transmission upgrade costs.
The company said it would not renew two point-to-point transmission agreements under which Public Service Electric and Gas takes 1,000 MW from Con Ed at the New York border and delivers it through New Jersey to Con Ed load in New York City.
Con Ed, which said it has identified less costly alternatives, informed the New York Public Service Commission of its decision in a letter May 2 (12-E-0503).
The company says that renewing the wheel after its April 30 expiration would expose it to $680 million in cost allocation charges for two transmission projects that it says primarily benefit New Jersey customers.
“Con Edison no longer requires power sources from the PJM wheel for reliability purposes, and unfair cost allocations have become too costly for our customers,” spokesman Bob McGee said. “Other electric projects added in recent years that already serve our customers will help us maintain reliability. We will continue to have access to the PJM wheel in an emergency.”
PJM assigned Con Ed $629 million of the costs of PSE&G’s $1.2 billion Bergen-Linden Corridor upgrade to address a short-circuit problem. PSE&G was allocated $52 million of the cost. Con Ed was also assigned $51 million of PSE&G’s $100 million Sewaren storm-hardening project.
Paul McGlynn, PJM general manager of system planning, told the PJM Planning Committee on Thursday of Con Ed’s intentions.
“We will need to make changes to the procedures we use in planning and operations,” he said. “This is just a heads-up that we’re going to need to be discussing it in the future. As plans take shape, we will be doing analysis on them. The goal is to discuss and determine how we will manage that interface without the wheel.
“When that wheeling agreement is canceled, we will need to redo cost allocations for any and all of the projects that Con Ed has allocation for, and we’ll have to file them at FERC. They would become effective when the agreement actually terminates in the spring of 2017,” McGlynn added.
“NYISO is working with PJM to develop an effective going-forward approach for the border,” ISO spokesman David Flanagan said. “In addition, NYISO will include this change in the full range of system information currently being gathered for the 2016 Reliability Needs Assessment that will study potential reliability needs for the period of 2017-2026.”
Bergen-Linden Corridor Upgrade Source: PSEG
Identification of the transmission projects that allowed Con Ed to cancel the wheel began in 2012, although for an entirely different reason. New York regulators at that time began discussions about transmission alternatives that would be needed if the Indian Point nuclear plant closed because its licenses were not renewed.
The NYPSC approved several projects in 2013 for that contingency, including three named the Transmission Owner Transmission Solutions. FERC in March accepted a cost allocation formula submitted by state regulators and New York transmission owners, including Con Ed. (See FERC OKs Settlement for NY TOTS Projects.)
One of the alternative projects, the $274.3 million “Staten Island Unbottling” would make 440 MW of generation available to the New York grid through Con Ed’s substations in a two-phase project.
However, in a February order, the NYPSC accepted a Con Ed motion to cancel the second phase. Con Ed said that once the wheel expired, transmission limitations caused by it would be eliminated and that only the $51.3 million first phase was necessary.
EPA said rules it issued Thursday to reduce methane emissions from oil and gas development will raise wholesale natural gas prices by less than 1%, but the industry’s leading trade group warned the “unreasonable and overly burdensome” regulations could depress shale gas development.
Infrared image of emissions from natural gas storage tank Source: Texas Commission on Environmental Quality
The agency said the rules will cost a net $320 million annually through 2020, with a $390 million total cost reduced by $70 million in revenue from sales of methane now lost into the atmosphere. By 2025, the estimated total cost increases to $640 million, offset by gas sales of $110 million, for a net cost of $530 million. The estimates, in 2012 dollars, assume a price of $4/Mcf.
EPA estimated that the rules will reduce gas well drilling by about 0.% and production by about 0.03% between 2020 and 2025, compared to the baseline. The agency estimated wellhead prices for onshore lower-48 production will increase during that period by about 0.2% and net imports will rise by about 0.11%.
Reduced Innovation?
The American Petroleum Institute said the costs will be more than twice EPA’s estimate, pegging them at $806 million per year in 2025.
“It doesn’t make sense that the administration would add unreasonable and overly burdensome regulations when the industry is already leading the way in reducing emissions,” Kyle Isakower, API’s vice president of regulatory and economic policy, said in a statement. “Imposing a one-size-fits-all scheme on the industry could actually stifle innovation and discourage investments in new technologies that could serve to further reduce emissions.”
The new rules are designed to reduce fugitive methane emissions from compressor stations, gas processing plants and well sites, including fracking operations. The rules also cover pneumatic pumps and controllers, centrifugal compressors and reciprocating compressors. Well site compressors are exempt.
Monitoring
The rules — which cover new and modified operations — are stringent, requiring substantially greater monitoring and emissions control than before across all areas of the extraction and production process. Well sites will be required to conduct biannual monitoring using either an infrared camera or a vapor “sniffer” and must repair leaks within 30 days. Compressor stations must be quarterly. Natural gas processing plants are already checked this way for other emissions, but they now must include methane.
Gas Separator Source: EPA
After fracking a well, operators will need to install equipment that separates gas from the fluid that flows back to the surface and collect or combust it. Wildcat, exploratory and low-pressure wells are required to have combustion devices but not the separation equipment.
Many of these operations were already regulated for volatile organic compounds (VOCs) and hazardous air pollutants (HAPs) — but not methane — under the 2012 New Source Performance Standards, which regulate pollutant emissions from new or modified sources. The new rules also include several edits to the NSPS, including how flares can be done, leak detection and repair, and monitoring and testing of storage-vessel control devices.
EPA said the rules are justified because the costs will be outweighed by “monetized climate benefits” of $360 million in 2020 and $690 million in 2025. Such benefits were calculated in relation to greehouse gas emissions only, but the agency said there will be additional benefits from the associated reductions in VOCs and HAPs.
Methane is second only to carbon dioxide in its overall contribution to global warming. A ton of methane traps 25 times as much heat in the atmosphere as the same amount of CO2 over a 100-year period.
The changes to the NSPS were released along with two other rules affecting the industry. One requires emissions reductions for operations on certain Native American lands. The other clarifies what equipment should be grouped together to calculate whether a site is a major or minor emissions source.
EPA estimates about 270 full-time equivalent workers will be needed to meet compliance. The agency estimates that will increase to about 1,800 in 2025.
The Public Utilities Commission of Ohio agreed Wednesday to hear FirstEnergy’s arguments for why it should be able to withdraw its controversial power purchase agreement and substitute a new plan.
It also granted all of the applications for rehearing sought by opponents of the PPA, including the Electric Power Supply Association, the Ohio Consumers’ Counsel, the Environmental Defense Fund, the Sierra Club, the Retail Energy Supply Association and the PJM Power Providers Group.
“Because of the number and complexity of the assignments of error raised in the applications for rehearing, as well as the potential for further evidentiary hearings in this matter, we find that it is appropriate to grant rehearing at this time,” the commission said (14-1297-EL-SSO). “This will allow parties to begin discovery in anticipation of potential further hearings.”
Although its rehearing request also was granted, the EDF protested the ruling.
“So, without listening to the arguments against the deal, the PUCO rubberstamped [FirstEnergy’s] request for a rehearing,” the EDF’s Dick Munson wrote in a blog post that went up within minutes of PUCO’s order.
Both FirstEnergy and American Electric Power were granted eight-year PPAs after more than a year of legal wrangling. But their victories were short lived, as FERC ruled that the agreements would require a review that could nullify them.
Opponents Sound Off
On Thursday, PUCO received a stream of filings against the modified FirstEnergy plan, including those from the Ohio Energy Group, the Northeast Ohio Public Energy Council, the Sierra Club, the PJM Power Providers Group (P3) and the Electric Power Supply Association.
P3 and EPSA accused FirstEnergy of doing an end-around play to avoid review by FERC. FirstEnergy, they said, is wrongly “attempting to use the commission’s application for rehearing process to circumvent the FERC order.”
“FirstEnergy, however, has made a mistake in how it presented its new PPA proposal to this commission,” they wrote. “FirstEnergy did not include or mention its new proposal in its application for rehearing, robbing the commission of jurisdiction over the proposal in this proceeding. This means that the commission cannot grant rehearing on the proposal and, contrary to its May 11, 2016, action, cannot reopen this proceeding to allow discovery on the proposal. The proposal is dead on arrival and the commission must follow the law by not exercising jurisdiction through rehearing.”
The Sierra Club also filed in opposition to the FirstEnergy plan.
“While FirstEnergy is trying to put old wine in a new bottle to escape review under federal customer protection standards, its latest shareholder bailout proposal is the same bad deal for Ohio customers,” said Shannon Fisk, managing attorney at Earthjustice, which represents the Sierra Club. “FERC smartly put a hold on FirstEnergy’s bailout so that customers would not be losing money while the legality of the bailout is fully reviewed. PUCO should not sign off on FirstEnergy’s brazen effort to evade FERC’s order.”
Thursday was also the deadline for arguments against AEP Ohio’s request to modify its PPA, and that docket also swelled with filings from opponents.
FERC ruled April 27 that the PPAs — in which AEP’s and FirstEnergy’s regulated utilities would purchase output from the companies’ merchant generators — must be reviewed under the Edgar affiliate abuse test (EL16-33 and EL16-34).
AEP CEO Nick Akins said after FERC’s ruling that the company would either lobby Ohio lawmakers to reregulate the state’s electricity market or sell off its Ohio fleet rather than submit to FERC review. FirstEnergy CEO Chuck Jones has also said he would welcome reregulation. (See All Eyes on AEP, FirstEnergy with Ohio PPAs in Doubt.)
Both utilities then filed for rehearing with PUCO. FirstEnergy asked the commission to withdraw its PPA and replace it with a customer charge that would still protect its aging power plants. Munson called FirstEnergy’s new plan “sleight of hand” and said PUCO’s decision Wednesday “suggests commissioners care more about appeasing a politically connected company than protecting customers or considering both sides of an argument.”
AEP Request
AEP scaled back its original request for PPAs for all of its 3,100-MW Ohio merchant fleet, asking PUCO for an agreement covering only its 440-MW share of the Ohio Valley Electric Corp. (14-1693-EL-RDR, 14-1694-EL-AAM). AEP said it will stand by its commitment to develop 900 MW of renewable energy — a promise that convinced the Sierra Club to sign on to its plan — with certain provisos.
On Thursday, the Office of the Ohio Consumers’ Counsel and the Appalachian Peace & Justice Network jointly filed a memorandum urging PUCO to deny AEP’s request to change its “electric security plan” (ESP).
“Even though AEP Ohio appears to have shuttled its plans for an affiliate PPA, in light of FERC’s rulings, it nonetheless has come up with another way to extract money from customers,” the two organizations wrote. They said AEP Ohio’s idea to seek a PPA covering only the OVEC portion of its generating fleet was already denied once by PUCO in a 2015 decision. “There is no reason to stray from that decision,” they wrote. PUCO at that time, they said, ruled that a OVEC-only PPA rider “would not provide a sufficiently beneficial financial hedge, or other commensurate benefits, to AEP Ohio’s customers to justify approval.”
“The PUCO should also consider that when AEP Ohio negotiated the OVEC contract, it agreed to an allocation of risk regarding Capacity Performance penalties and bonuses,” the groups argued. “The PUCO should not undo the deal that AEP Ohio itself struck by bailing it out from the agreed-to risk allocation and imposing the risk on customers.”
The groups also argue that PUCO’s rules don’t allow AEP Ohio to modify the ESP. It only allows it to accept PUCO’s modifications or withdraw and terminate its entire request, they said.
P3 and the Electric Power Supply Association also argued that AEP’s rehearing request and “rehashed proposal” should be denied, also noting PUCO’s 2015 ruling.
“With the affiliate PPA removed from the PPA rider, AEP Ohio is left with only its OVEC entitlement — a construct this commission expressly rejected in 2015,” they wrote. “The commission should deny AEP Ohio’s application for rehearing, reverse its approval of the stipulation and terminate this hearing.”
The Mid-Atlantic Renewable Energy Coalition filed a memo supporting AEP’s rehearing request, saying it is necessary to “preserve the significant public policy benefits” of the original renewable energy agreements.
FERC late Tuesday rejected multiple rehearing requests on PJM’s Capacity Performance rules, but ordered the RTO to revise Tariff language regarding auction revenue rights and clarify language on several other issues, including risk premiums and “nonphysical” constraints.
The ruling, on the eve of PJM’s Base Residual Auction Wednesday, granted only one rehearing request, ordering the RTO to change its force majeure rules regarding load-serving entities’ ARRs (ER15-623, EL15-29, EL15-41).
The commission rescinded its approval of Tariff language allowing the RTO to deny financial transmission rights awards for an “unanticipated event outside the control of PJM.” The commission had agreed that PJM should have some discretion in determining when to relax a binding constraint in allocating FTRs. (FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.)
American Municipal Power, Old Dominion Electric Cooperative and Southern Maryland Electric Cooperative complained that the change could affect LSEs’ shares of stage 1A ARRs and thus their abilities to hedge transmission costs.
The complainants said the language was different from PJM’s other force majeure changes because it applied to PJM’s obligations to LSEs rather than market participants’ performance obligations.
They argued the revised Tariff lacked any limits on PJM’s exercise of its discretion. In most cases, they added, FTR allocations will have already been made or be underway before PJM makes its decisions, leaving them facing “the prospect of an unlikely post-settlement remedy.”
FERC agreed.
“Upon further consideration, we agree that PJM has not adequately explained why its existing rules are unjust and unreasonable regarding its duties to load-serving entities as they relate to the allocation of ARRs and FTRs,” it said, ordering the RTO to reinstate “its prior just and reasonable” Tariff language.
Nonperformance Charges
The commission also required several revisions to PJM’s July 29, 2015, compliance filing in response to FERC’s June 9 order conditionally approving Capacity Performance. (See FERC OKs PJM Capacity Performance: What You Need to Know.)
One required change concerns whether a capacity resource will be subject to nonperformance charges if PJM does not schedule it solely because of operating parameter limitations in the resource’s offer.
FERC said a literal reading of the Tariff suggests that a provision exempting resources from the nonperformance charge if the resource is not scheduled through PJM’s security-constrained economic dispatch takes precedence — meaning a resource’s undelivered megawatts would not be counted as a performance shortfall even if it would otherwise be needed.
“This outcome is inconsistent with the commission’s finding in the Capacity Performance order,” it said.
It directed PJM to revise the Tariff “to make clear that, notwithstanding PJM’s determination that a scheduling action was appropriate to the security-constrained economic dispatch of the PJM region, any undelivered megawatts will be counted as a performance shortfall if such megawatts otherwise would be needed but for an operating parameter limitation specified in the market seller’s energy offer.”
Fixed Resource Requirement Phase-in
The commission also found fault with PJM’s proposal to apply the Capacity Performance rules to all fixed resource requirement (FRR) entities beginning with the 2019-20 delivery year.
FERC said the proposal to apply Capacity Performance rules to FRR entities with no ongoing five-year election commitment beginning with delivery year 2020/21 was “reasonable in concept.”
But it said its intent was that the rules would not apply to an entity that was within its initial five-year FRR commitment period when the CP order was issued, meaning an entity that first elected to use the FRR option for delivery year 2015/16 would not become subject to the rules until delivery year 2020/21.
“PJM’s proposed compliance to apply the Capacity Performance requirements to all fixed resource requirement entities beginning with the 2019/20 delivery year is therefore not consistent with the commission’s intent,” it said.
Quantifiable Risk
NRG Energy, Dynegy, Public Service Enterprise Group, the PJM Power Providers Group and the Independent Market Monitor won their requests for clarification of Tariff language regarding “quantifiable risks” of becoming a capacity resource.
The commission said it disagreed with complaints that PJM’s language narrowed sellers’ ability to include quantifiable, reasonably supported risks in their offers.
But it required the RTO to clarify that the method it described for justifying such risks was not all-inclusive “and that a capacity market seller may use other methods or forms of support for a risk premium to meet the ‘reasonably supported’ threshold.”
“The risk that market sellers face from becoming capacity resources under the new capacity market construct requires a complex calculation that depends on the company-specific nature of valuing performance risk,” the commission said.
PJM had said a risk would be considered reasonably supported “if it is based on actuarial practices generally used by the industry to model or value risk and … used by the capacity market seller to model or value risk in other aspects of the capacity market seller’s business.”
Nonphysical Constraints
FERC also said PJM went too far in requiring that gas generators seeking to qualify for consideration of “legitimate, constraints unrelated to the characteristics of the unit” — which PJM calls nonphysical constraints — must obtain the most flexible gas pipeline transportation contract.
The commission said PJM’s filing went beyond the scope of its compliance directive requiring the RTO to allow parameter limitations for operational constraints.
“PJM’s proposal also is unclear since operational constraints imposed by a gas pipeline may have little relationship to the underlying flexibility of a transportation contract, but are related to pipeline operational characteristics, and cannot be eliminated by contract term or service choice,” the commission said.
“Furthermore, we find that provision unduly discriminatory as it establishes a prerequisite applicable only to gas generators. We also agree with protesters that the language is vague and would require PJM to exercise significant discretion in determining whether a generator has obtained the most flexible contract available.”
It ordered the RTO to remove the offending language from its Operating Agreement and Tariff and to “make explicit that the revisions here do not preclude resources other than natural gas generators from establishing legitimate, nonphysical constraints.”
Bay Again Dissents
Chairman Norman Bay, who voted against the original Capacity Performance order, also opposed the latest ruling, issuing an 11-page dissent reiterating his position that the construct’s “multi-billion-dollar cost to consumers exceeds the benefits.”
“Furthermore, and equally important, the market design itself is flawed. Compensation for capacity resources is so generous, and the penalties for nonperformance are so weak, that resources can profit even if they are unable to perform when they are most needed, thereby undercutting the very purpose of the program,” he said.
Gov. John Kasich on Monday named Public Utilities Commission of Ohio Vice Chair Asim Haque to replace outgoing Chairman Andre Porter.
Porter announced last month that he would be leaving the commission on May 20. While Porter, who served little more than a year, hasn’t said where he would be going, industry speculation has him taking a position with MISO. The RTO has declined repeated requests to comment on the speculation.
Asim Haque Source: PUCO
Haque, appointed to the commission three years ago by Kasich, will be the fourth PUCO chairman in four years. Haque will be guiding the commission through the ongoing controversy over power purchase agreements for American Electric Power and FirstEnergy.
“Throughout his three years of service on the PUCO, Commissioner Haque has demonstrated an exceptional command of the issues and challenges facing Ohio’s energy markets. No one is better prepared to apply that level of expertise and independent judgment to the role of chairman,” Kasich said.
“I am honored by the governor’s confidence in my ability to lead the commission, and I look forward to working with my fellow commissioners and the talented PUCO staff to foster energy policies that further strengthen Ohio’s job growth with affordable, reliable power,” Haque said.
Haque has bachelor’s degrees in chemistry and political science from Case Western Reserve University and a law degree from the Ohio State University Moritz College of Law.
A nominating council will now have to come up with four names to submit to Kasich for consideration to fill Haque’s old seat, a process that could take months.
The U.S. Commodity Futures Trading Commission said Tuesday that it is amending its 2013 order exempting RTO energy transactions from certain provisions of the Commodity Exchange Act to clarify that it does not bar private rights of action.
The proposed amendment, approved in a 2-1 vote, would “explicitly” provide that the RTO-ISO order does not prevent private parties from filing lawsuits.
CFTC said the private right of action’s existence is “not inconsistent with or detrimental to cooperation between the CFTC and FERC.” Preserving that right, the commission said, “will not cause regulatory uncertainty or duplicative or inconsistent regulation.”
“Moreover, conflicting judicial interpretations regarding the nature of the covered transactions would not affect the jurisdiction of FERC or any relevant state regulatory authority.”
The amendment stems from CFTC’s April 2013 order, which exempted financial transmission rights and other electricity transactions subject to tariffs approved by FERC or the Public Utility Commission of Texas from most of the CEA’s provisions, while retaining its general anti-fraud and anti-manipulation authority.
SPP was the only grid operator not party to the order, as its day-ahead market did not become fully operational until March 2014. The RTO sought the same exemptions that the commission granted the others, but the commission’s May 2015 draft order on SPP included a preamble stating its intent to preserve private rights of action under Section 22 of the CEA.
Although the commission said it did not intend to exclude private suits in its 2013 order, the 5th Circuit Court of Appeals ruled in February that it had done so. The appellate court upheld a 2015 ruling by the U.S. District Court for the Southern District of Texas dismissing a lawsuit alleging that some generators in ERCOT were intentionally withholding electricity and manipulating prices in the derivatives commodities market (Aspire Commodities v. GDF Suez Energy N. Am., No. H-14-1111). The court said that the private right of action was “unavailable to [p]laintiffs” due to the CFTC’s exemption order.
In March, the ISO/RTO Council, the Texas PUC, the Edison Electric Institute and other witnesses asked the commission to reverse its position, saying the SPP order could undermine the broad exemptions earlier granted to the other grid operators. PJM, ERCOT and CAISO also raised objections last year.
Last month, U.S. Sen. John Boozman (R-Ark.) introduced an amendment to CFTC’s reauthorization bill that would prevent the agency from adding the private rights option to the 2013 order. (See Congress May Order CFTC to Back Down on Private Rights.)
CFTC Chairman Timothy Massad said he appreciated “the desire of businesses to have as little regulatory uncertainty as possible” but that the commission must also ensure “there is adequate recourse” for market participants.
“Private rights of action have been instrumental in helping to protect market participants and deter bad actors,” Massad said in a statement. “These actions can also augment the limited enforcement resources of the CFTC and serve the public interest by allowing harmed parties to seek damages in instances where the commission lacks the resources to do so on their behalf.”
In a lengthy dissent, Commissioner J. Christopher Giancarlo said the amendment “manages to simultaneously toss legal certainty to the wind and threaten the household budgets of low- and middle-income ratepayers by permitting private lawsuits in heavily regulated markets that are at the heart of the U.S. economy.”
The proposed amendment will be open for public comment for 30 days once it is published in the Federal Register.
After a yearlong battle to win approval from Ohio regulators for their controversial power purchase agreements, FirstEnergy and AEP Ohio asked the state last week to start over.
FirstEnergy asked the Public Utilities Commission of Ohio to withdraw its PPA and replace it with a customer charge that would still protect its aging power plants (14-1297-EL-SSO).
Kyger Creek Plant Source: OVEC
AEP whittled down its original request for PPAs for all of its 3,100-MW Ohio merchant fleet, asking PUCO for agreements covering only its 440-MW share of the Ohio Valley Electric Corp. (14-1693-EL-RDR, 14-1694-EL-AAM). AEP said it will stand by its commitment to develop 900 MW of renewable energy — a promise that convinced the Sierra Club to sign on to its plan — with certain provisos.
Both AEP and FirstEnergy are seeking to reformulate their plans in order to avoid a review by FERC. The commission ruled April 27 that the PPAs — in which AEP’s and FirstEnergy’s regulated utilities would purchase output from the companies’ merchant generators — must be reviewed under the Edgar affiliate abuse test (EL16-33 and EL16-34).
AEP CEO Nick Akins said the company would either lobby Ohio lawmakers to reregulate the state’s electricity market or sell off its Ohio fleet rather than submit to FERC review. FirstEnergy CEO Chuck Jones has also said he would welcome reregulation. (See All Eyes on AEP, FirstEnergy with Ohio PPAs in Doubt.)
FirstEnergy is asking for an expedited ruling from the commission by May 25. The deadline for parties to respond to AEP’s and FirstEnergy’s new proposals is May 12.
Rehearing Requests
The companies’ new requests came on the deadline for PPA opponents to seek rehearing of PUCO’s March 31 ruling.
Among those renewing their call for rejection of the PPAs were the Electric Power Supply Association, the Ohio Consumers’ Counsel, the Environmental Defense Fund, the Sierra Club (which is opposing the FirstEnergy deal but is still a party to the AEP agreement), the Retail Energy Supply Association and the PJM Power Providers Group.
The OCC noted that FERC rescinded the waivers “under which AEP Ohio claimed it could proceed with the PPA without FERC review, [so] accordingly, the PPA rider is effectively dead.”
Shannon Fisk, managing attorney at Earthjustice, a nonprofit law firm representing the Sierra Club, said Friday that FirstEnergy’s newest filing was “a transparent attempt to avoid FERC review.” He said he hopes PUCO “won’t join with FirstEnergy to snub FERC.
“It would be seriously inappropriate for a state commission to do that,” he said.
AEP Wants Stake in Renewable Projects
In its latest filing, AEP said it is committed to the renewable portion of its PPA agreement but wants to own half of the projects, rather than purchasing the power on the market. “This is especially vital given that AEP Ohio is attempting to fully honor the renewable commitment even though the previously featured affiliated PPA is no longer part of the PPA proposal,” the company wrote.
“The company is productively attempting to salvage rather than terminate the commitments made as part of the beneficial package of the stipulation in a reasonable and modest way,” it wrote. “The company is pursuing this even though the central feature of the affiliated PPA is no longer included.”
We are proud to announce the initiation of the RTO Insider Top 30, the first in what will be a quarterly review of the top publicly traded companies (by market capitalization) with significant presence in the seven RTOs and ISOs in the U.S.
Any list is bound to provoke debate — and we trust this will be no exception. It’s a particular challenge in the ever-changing electric industry, as new technologies, environmental mandates and other factors force shifts in business models and regulatory rules.
The list includes both integrated utilities and independent power producers. It doesn’t include some companies such as out-of-the ashes Dynegy and EnerNOC, whose voices in policy matters outweigh their market capitalizations.
This new initiative also coincides with our expansion to CAISO and its expanding Energy Imbalance Market. So the list includes companies such as Pinnacle West Capital (parent of Arizona Public Service), Sempra Energy, Pacific Gas and Electric, Edison International (parent of Southern California Edison), about which we haven’t written much before. We’ve also included Berkshire Hathaway Energy, which reports its financials as if it were a standalone company although it trades as part of Warren Buffet’s Berkshire Hathaway holding company.
So, consider this a beta test and share your feedback with us. We expect to refine — and perhaps enlarge — this list in the future.
Company
Mkt cap ($ billions)
Revenue Q1 2016 ($ billions)
% change vs. 2015
Net income Q1 2016 ($ millions)
% change vs. 2015
NextEra Energy
$54.51
$3.84
-7%
636
-2%
National Grid
$54.15
***
***
***
***
Duke Energy
$54.14
$5.62
-7%
$699
-19%
Dominion Resources
$43.48
$2.92
-15%
$524
-2%
Exelon
$33.15
$7.57
-14%
$123
-83%
American Electric Power
$31.43
$4.00
-13%
$501
-20%
Pacific Gas and Electric
$29.19
$3.97
2%
110
224%
Berkshire Hathaway Energy
NA
$4.04
-4%
$495
5%
Sempra Energy
$25.97
$2.62
-2%
330
-28%
PPL
$25.91
$2.01
-10%
$481
-26%
Edison International
$23.35
$2.44
-3%
296
-7%
Public Service Enterprise Group
$22.75
$2.62
-17%
$471
-20%
Consolidated Edison
$21.38
$3.16
-13%
$310
-16%
Xcel Energy
$20.36
$2.77
-6%
$241
59%
WEC Energy Group
$18.48
$2.20
58%
$347
77%
Eversource Energy
$18.06
$2.06
-18%
$244
-4%
DTE Energy
$15.97
$2.57
-14%
$240
-12%
FirstEnergy
$13.88
$3.87
-1%
$328
48%
Entergy
$13.54
$2.61
-11%
$230
-23%
Avangrid
$12.46
$1.67
***
$212
100%
Ameren
$11.53
$1.43
-8%
$105
-3%
CMS Energy
$11.48
$1.80
-15%
$164
-19%
CenterPoint Energy
$9.31
$1.98
-18%
$154
18%
Alliant
$8.22
$0.84
-6%
$99
0%
Pinnacle West Capital
$8.08
$0.68
1%
$9
-55%
NiSource
$7.50
$1.45
-21%
$180
-7%
Westar Energy
$7.22
$0.57
-4%
$69
29%
OGE Energy
$5.91
$0.43
-10%
$25
-42%
Calpine
$5.59
$1.62
-2%
$(198)
NA
NRG Energy
$5.10
$3.23
-16%
$47
NA
Totals
$76.59
-7%
$7,472
-12%
***Companies had not reported as of press time.
Mild Winter Cuts Revenues
It wasn’t a very good quarter for most of the companies in our grouping. Largely because of a mild winter and continued low natural gas prices, revenues dropped by a median of 7% and net income both fell by a median of 7% in the first quarter of 2016 versus a year earlier.
Total profits declined by 12%, falling to $7.5 billion for the 29 companies that have reported thus far, from $8.5 billion for the same group a year earlier.
Companies in the RTO Insider Top 30 reported a median 10% drop in revenues in the first quarter of 2016 vs. 2015.
Only three companies saw an increase in revenue in the quarter, led by WEC Energy Group, which was formed last June from Wisconsin Energy’s acquisition of Integrys Energy Group. The merger boosted its top line 58% to $2.2 billion (see details below). PG&E and Pinnacle West showed modest revenue gains.
Excluding the incremental $980 million in revenue WEC gained from Integrys, however, total revenues declined 8% to $75.6 billion.
Six companies saw an increase in net income: WEC, PG&E, FirstEnergy, Westar Energy, Xcel Energy and Avangrid, which was formed in December following Spanish conglomerate Iberdrola’s acquisition of UIL Holdings.
Avangrid’s net income for the quarter included a one-time gain of $17 million from the sale of its interest in the Iroquois Gas Transmission System.
All but one company was profitable for the quarter. Calpine showed a net loss of $198 million ($0.56/share), an increase from the $10 million loss ($0.03/share) reported a year earlier. The company’s revenues declined 2% to $1.62 billion. The company attributed the loss primarily to mark-to-market losses resulting from decreases in forward power and natural gas prices.
Below are some of the highlights from the first quarter.
– Rich Heidorn Jr.
Integrys Acquisition, Influx of New Customers Amplify WEC Q1 Earnings
WEC’s Integrys acquisition boosted first-quarter revenue, with earnings per share jumping 19 cents from $0.90 in 2015 to $1.09 in 2016.
“We are achieving the results we expected from the Integrys acquisition,” CEO Allen Leverett said in a conference call last week.
WEC recorded net income of $347 million, up from $196 million in the first quarter of 2015. The addition of Integrys boosted revenues by $980 million despite decreased demand over a mild winter.
Leverett said the company is serving 8,000 more electric customers and 11,000 more natural gas customers in Wisconsin compared to a year ago. Another 6,000 natural gas customers were added in the past year in Illinois, Michigan and Minnesota, and WEC gained 10,000 Minnesota natural gas customers from Alliant Energy in April 2015, Leverett reported.
On Monday, UBS Securities upgraded WEC to neutral from sell, citing the company’s projected 5 to 7% earnings-per-share growth rate.
– Amanda Durish Cook
PSEG: ‘New Urgency’ to Cost Cuts
Public Service Enterprise Group CEO Ralph Izzo blamed “the complete absence of a winter” in part for its 17% drop in revenues. Weather in PSEG’s service territory was 10% warmer than normal and the fifth warmest on record.
Izzo said low gas prices and stricter reliability requirements for capacity resources in PJM have “added new urgency to the company’s efforts to improve its cost structure and efficiency,” leading it to make what he called “judicious reductions” in its nuclear workforce.
The CEO also said the company “is working closely with the industry to identify additional means of reducing its cost structure” to keep its nuclear plants operating.
During an earnings call, Izzo was asked about the rationale for PSEG’s partnership with Indiana gas and electric utility Vectren to seek competitive transmission opportunities in MISO. “I think that there is a lot of value to be had by combining forces with someone who understands the local transmission grid and system with our expertise now having put over $2 billion to work on an annual basis for a good number of years in terms of cost and schedule management on transmission construction.”
Izzo said the company would continue to be judicious in its generation expansions. “We have demonstrated that we’re pretty bad at acquiring assets,” he said. “By that I mean we seem to have a more conservative view of where the market is going and are consistently outbid.”
– Rich Heidorn Jr.
Dominion Hoping Conn. Legislature will Help Millstone
Dominion Resources’ lackluster results — a 15% drop in revenue and net income down 2% — left CEO Thomas Farrell having to open his earnings call with analysts by boasting about the company’s No. 1 safety ranking among electric utilities in the Southeast. Occupational Safety and Health Administration “recordables for each of our business units were roughly one-half the level recorded last year, and last year had tied an all-time company record,” Farrell said.
He also took note of the beginning of commercial operations at Dominion’s 1,358-MW Brunswick County Power Station, “completed ahead of time and under budget.”
Farrell said the company is “much more interested” in solar than wind assets. “Wind is not a good asset in the territories where we do business for producing power reliably,” he said.
The CEO also said Connecticut lawmakers had ended their session without taking action on legislation that could aid the company’s Millstone nuclear plant. Farrell said he expects the Connecticut House to consider the bill, which cleared the Senate, when it reconvenes in January.
The bill could allow Millstone to sell up to half its power in a new market under long-term contracts.
“We’re following the legislation, obviously, closely,” Farrell said. “But I think it’s part of an overall dialogue that will take place over the next few months in New England generally about how to protect” Millstone and NextEra Energy’s Seabrook nuclear plant in New Hampshire.
– Rich Heidorn Jr.
CMS Energy Q1 Earnings Down on Record Warm Winter
CMS Energy attributed its first-quarter earnings decline to Michigan’s second-warmest winter on record.
John Russell, CMS’ outgoing CEO, said “weather was the primary factor” for why net income dropped 19% to $164 million. Mild temperatures undercut gas deliveries and electricity sales, while an upsurge in storm activity increased restoration-related expenses, Russell said during an April 28 call.
The Michigan-based company is the parent of Consumers Energy, which reduced its electric rates by $38 million annually (1%) effective with the April 15 retirement of its seven oldest coal plants. Consumers is using power from renewables and the recently acquired Jackson natural gas-fired plant to fill the gap.
“We retired seven coal plants totaling 950 MW, bringing our capacity mix to less than 25% coal,” Russell said.
Patti Poppe, senior vice president of distribution operations and incoming CEO, said CMS’ electric and gas distribution business can improve its per customer operation and maintenance cost, which is in the third quartile when compared with peer companies.
Russell, who retires July 1, also used the call to appeal for a change to a Michigan law that he said requires CMS customers to subsidize about 300 large customers by paying an extra 3 to 4% in their bills. “This is simply not fair,” he said. He said Consumers staff are willing to work with legislators on a new energy plan.
– Amanda Durish Cook
NRG Beats Expectations with $82M Net Income
NRG Energy’s first-quarter earnings surpassed Wall Street expectations, validating the company’s “integrated competitive power platform,” CEO Mauricio Gutierrez said.
“We are off to a really good start for the year,” Gutierrez said during a conference call May 5. “We have turned the page on this period of uncertainty.”
The company reported first-quarter net income of $47 million after losing $136 million during the same period a year earlier. Earnings per share came in at 24 cents, after some analysts had predicted losses averaging 17 cents/share. NRG posted $3.23 billion in revenue for the quarter.
Gutierrez said the company has made “significant progress” in its goal of selling $500 million in assets this year, pointing to $138 million in sales during the quarter. NRG also announced the sale of its stake in the electric vehicle charging business, EVgo, to Vision Ridge Partners for total consideration of approximately $50 million, and the streamlining of its residential solar program in its retail business.
The company’s effort to transform coal plants to gas offers opportunities in the ERCOT market, Gutierrez said. “We’re optimistic … as we see up to 9 GW of coal generation at risk due to upcoming environmental regulations and strong growth,” he said, also noting revisions to the operating reserve demand curve will increase scarcity pricing. (See ERCOT: No Consensus on Operating Reserve Changes.)
– Tom Kleckner
Earnings call transcripts courtesy of Seeking Alpha.
FERC last week released an environmental assessment of the Atlantic Bridge natural gas pipeline expansion project, finding “no significant impact” (CP16-9).
Atlantic Bridge Project Map Source: Spectra Energy
Spectra Energy has proposed expanding its Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems’ capacity by 132,700 dekatherms/day to serve the New England and Canadian natural gas markets.
Six miles of existing pipeline in New York and Connecticut would be widened from 26 inches to 42 inches. A 7,700-horsepower compressor station would be built in Massachusetts, along with numerous infrastructure improvements.
The project has a proposed in-service date of November 2017. Public comment on the project is open until June 1.
While only a fraction of the size of other natural gas projects seeking to tap into abundant shale gas from Pennsylvania, the project has provoked opposition from climate change activists and landowners fearing encroachments on their properties. (See Hearing on Algonquin Pipeline Expansion Highlights Local, National Issues.)
The developers have commitments from New England gas distribution companies and manufacturers for 40% of the additional capacity, with the other 60% committed to commercial and industrial customers in the Canadian Maritime provinces. The developers say none of the gas is destined for the LNG export terminals proposed in Maine or the Maritimes, a major source of controversy for any infrastructure expansions in New England.
“The additional supply from Atlantic Bridge will help enhance the reliability of energy throughout the region and generate savings for homeowners, businesses and manufacturers,” according to Spectra.
FERC said its review did not find significant issues that rise to the level of requiring a more extensive environmental impact statement.
A PJM analysis released last week concludes that the RTO’s markets are efficiently managing the entry and exit of capacity resources but warns their efforts could be hamstrung by policies to protect social, economic or political interests.
“Realizing the ‘investment efficiency’ advantages of PJM’s markets can require policymakers to accept tough choices because efficient market outcomes may inflict harm to other policy objectives,” said the 45-page report, titled “Resource Investment in Competitive Markets.”
“Policymakers must weigh these trade-offs, but understand that pursuing individual actions that ‘defeat’ efficient market outcomes will aggregate to a point they will altogether thwart effective operation of the market to the point it can no longer be relied upon to govern resource exit and entry and attract capital investment when needed,” it said.
Informed Decisions
Presenting the study in a conference call with the news media Friday, PJM General Counsel Vince Duane said, “It’s important to ensure that policymakers are making informed decisions when they decide to go with one approach at perhaps the expense of another.”
The report was commissioned by the Board of Managers last summer, following efforts by money-losing coal-fired generators in Ohio and nuclear generators in Illinois to win state-backed subsidies.
The Public Utilities Commission of Ohio is grappling with how to respond to a recent FERC order requiring federal review of power purchase agreements it granted to American Electric Power and FirstEnergy. (See related story, AEP, FirstEnergy Revise PPA Requests to Avoid FERC Review.)
Meanwhile, Exelon CEO Christopher Crane said in an earnings call on Friday that if Illinois legislators don’t step in and provide aid, it will decommission its money-losing Clinton and Quad Cities nuclear plants beginning next year. (See related story, Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)
Local Consequences
“There’s no question that the retirements of legacy generation can create disruptive effects to local economies, job loss, loss of tax revenues for local communities,” Duane said. “Our markets are not designed — and really shouldn’t be designed — to account for those kinds of policy interests. But nonetheless they have to work alongside programs that are intended to advance social and political, environmental issues.
“The message is … let’s acknowledge there are trade-offs from time to time. Those trade-offs could be minimized perhaps if externalities can be priced and then the market can more readily digest those policy choices. … But that’s not always possible.”
The analysis is composed of two parts. The first “examines how markets drive resource investment decisions and compares generation entry and exit outcomes under both market and traditionally regulated constructs.”
The second section looked at “subsidies, regulations, policies and other requirements that may either reward or disadvantage generating resources and how such actions affect the performance of markets.”
On the first subject, researchers concluded that competitive markets are efficient when left alone to manage resource entry and exit, and that they do this on a more cost-effective basis for consumers than under a regulated model.
Bearing the Risk
At the same time that PJM is encouraging cost-effective new generation, it is avoiding investment in risky, capital-intense, experimental utility-scale projects such as Southern Co.’s Kemper integrated gasification combined cycle project and the Vogtle nuclear plant’s Units 3 and 4. The projects, backed by state and federal subsidies in traditional, rate-regulated states, are years behind schedule and billions over budget.
“Over the long term, markets can misallocate capital — we’re not saying it’s just a problem with regulators,” Duane said. “But markets also move very quickly” to correct their mistakes.
“We are operating … in very uncertain times in this industry right now,” he continued. “There’s a lot of concern about the disruption of the business model. Risk has a price, has a cost. In market environments like PJM’s, that risk is owned by the merchant investor. … Regulated entry is underwritten by the consumer/ratepayer.”
On a risk-adjusted basis, he said, “it seemed that new combined cycle entry was coming in to PJM on highly favorable terms relative to regulated models. Consumers of merchant generation in PJM were getting a pretty good deal.”
That, he said, raised two questions: Were regulated markets allowing returns on equity that were too high compared with what an investor would require? And on the other hand, was PJM providing sufficient revenues to support investments?
Given that 140,000 MW of natural gas capacity has entered the project queue since 2010, he said, “It’s hard to imagine that sophisticated investors are deploying their capital in PJM in that manner if they’re not expecting adequate returns.”
Resources Not Retiring Prematurely
The study also helps PJM rebut allegations that it is prematurely retiring resources that still have a useful life, Duane said.
“We were able to conclude with a high degree of confidence that both regulated models and PJM are doing a pretty good job in exiting coal resources that are really no longer competitive. But we were unable to see any meaningful statistical distinction that we were more aggressive or unduly aggressive or starving resources that still had an economic life but were unable, based on the market design, to earn the revenues that they should to support their operations,” he said.
PJM’s Tom Zadlo, who joined Duane on the media call, said PJM’s markets could accommodate a cap-and-trade system that would improve the finances of nuclear plants. “At a very simple level, if it’s something you can put a price on, it’s something that the market can then optimize for,” he said.
But the study did not make recommendations for how policy objectives can be designed in ways that don’t thwart market economics. “We leave that for another day,” Duane said.
The company says that renewing the wheel after its April 30 expiration would expose it to $680 million in cost allocation charges for two transmission projects that it says primarily benefit New Jersey customers.
WEC’s Integrys acquisition boosted first-quarter revenue, with earnings per share jumping 19 cents from $0.90 in 2015 to $1.09 in 2016.
Public Service Enterprise Group CEO Ralph Izzo blamed “the complete absence of a winter” in part for its 17% drop in revenues. Weather in PSEG’s service territory was 10% warmer than normal and the fifth warmest on record.
Dominion Resources’ lackluster results — a 15% drop in revenue and net income down 2% — left CEO Thomas Farrell having to open his earnings call with analysts by boasting about the company’s No. 1 safety ranking among electric utilities in the Southeast. Occupational Safety and Health Administration “recordables for each of our business units were roughly one-half the level recorded last year, and last year had tied an all-time company record,” Farrell 
CMS Energy attributed its first-quarter earnings decline to Michigan’s second-warmest winter on record.
NRG Energy’s first-quarter earnings surpassed Wall Street expectations, validating the company’s “integrated competitive power platform,” CEO Mauricio Gutierrez said.
