NiSource lost $52.4 million during the fourth quarter due to one-time charges related to the federal tax cuts passed late last year, the company said Tuesday.
But during a Feb. 20 earnings call, CEO Joe Hamrock focused on adjusted earnings, noting the company would have made $110.3 million ($0.33/share) in the fourth quarter absent the charges — beating analyst estimates by a penny. The Merrillville, Ind.-based company earned $88.8 million ($0.28/share) during the fourth quarter of 2016.
Hamrock said that “2017 was a year of solid execution,” aided by record utility infrastructure and a growing customer base helped by an upswing in the housing market. NiSource added 28,000 new customers in 2017.
“We’re well positioned for continued growth,” Hamrock told investors.
NiSource earned $128.6 million ($0.39/share) for the year, compared with $328.1 million ($1.02/share) in 2016. Still, the company’s 5% increase in operating income to $901.6 million was accompanied by a 72% jump in income taxes — to $314.5 million — based on “certain balance sheet adjustments and other items as a result of federal tax reform legislation,” the company said.
Chief Financial Officer Donald Brown said NiSource’s continuing commitment to utility investment will be boosted by last year’s federal tax law change despite the non-recurring write-down. Hamrock said the company continues to work with stakeholders and regulators in the seven states it serves on how to best pass the benefits of tax reform on to customers.
“This effort should play out over the next six months or so,” Hamrock said.
During 2017, the company refinanced almost $1 billion of its long-term debts at more favorable rates, which is expected to result in “significant interest savings and positively impact its earnings,” according to the company.
NiSource also invested $1.7 billion in infrastructure last year, the company’s largest-ever single-year investment, Hamrock said. The investment involved replacing 377 miles of gas pipeline, replacing 1,300 electric poles, and placing 68 miles of underground electric cable.
The company’s future financials will be helped further by a recent settlement over the cleanup of several coal ash ponds at two of its Northern Indiana Public Service Co. coal plants. The Indiana Utility Regulatory Commission in December approved a settlement allowing the utility to recover 80% of federally mandated costs to clean up the ponds through surcharges in customer bills (44872). The $193 million bundle of projects ― at Michigan City Unit 12 in Michigan City, Ind., and at R.M. Schahfer Units 14 and 15 in Wheatfield, Ind. — is expected to bring NIPSCO in compliance with EPA’s Coal Combustion Residuals rule. The other 20% of project cost recovery will be deferred until NIPSCO’s next rate case before the IURC.
Michigan City generating station | NIPSCO
Hamrock said NiSource expects to complete the environmental mitigation project by the end of this year.
He also said the company is still on track to reduce its greenhouse gas emissions 50% from 2005 levels by 2025. NiSource last year announced plans to retire half its coal generation by 2023, shuttering more than 1.2 GW in coal between its Bailly and Schahfer plants. (See Big Spending, Shrinking Coal Fleetin NiSource’s Future.) NIPSCO officials have said new EPA rules on coal ash contributed to the company’s decision to partially close Schahfer.
WASHINGTON — Resilience, pipelines and the Public Utility Regulatory Policies Act topped the discussions at the National Association of Regulatory Utility Commissioners’ winter meetings last week, which were attended by hundreds of state regulators, utility officials and other industry stakeholders. Here are some of the highlights:
‘Beacon of Stability’
All five FERC commissioners spoke about grid resilience and how RTOs and ISOs should plan to address it.
Commissioner Neil Chatterjee said he hoped FERC’s response to the Department of Energy’s Notice of Proposed Rulemaking assuaged some fears about the commission’s impartiality.
“I’m increasingly gaining appreciation for the role the commission plays … to be a beacon of stability in an otherwise volatile regulatory and legislative landscape,” he said during a panel for NARUC’s Committee on Gas. “I understand why people were concerned. You have four new commissioners coming in, and here’s [Senate Majority Leader Mitch] McConnell’s coal guy. People were concerned that the right decision would get made. I hope now that, in the aftermath, … that people … around the country will have confidence that we’re going to continue going forward in a fuel-neutral, nonpolitical, reasonable way.”
He acknowledged his sympathy for efforts to save coal, given his Kentucky origins.
“The significance of coal-fired generation and the mines, the role they play in the economy, it goes beyond energy and reliability. It really is part of the lifeblood of some communities. … When the plants close, the mines close, the jobs go away, people are left, their only asset is their homes and oftentimes those homes, they have no value because of the lack of economic opportunity, so it’s really, really difficult. Of course, I was sympathetic to the plight of the people in my home part of the country.”
FERC Chairman Kevin McIntyre defended the NOPR as “widely misunderstood by many in the industry” but also acknowledged it had not been a priority for the commission.
“Some of the items we work are actually of our choosing. Others are foisted upon us,” he said.
McIntyre acknowledged that state and federal policy “do overlap in some ways” and assured attendees that the commission takes its rulemaking responsibilities “very seriously.”
“That makes it hard. One cannot simply say, ‘OK, that sounds close enough for us,’” he said. “This country has benefited enormously from robust, competitive markets, so one has to be very careful taking any steps that could have the result of, or even be perceived as, casting aside recognition of those important market benefits.”
Commissioner Robert Powelson told attendees at a Committee on Water panel that he expects any proposal from an RTO to have state support. He said “unequivocally” that any proposal “will not garner any support if I don’t hear from the … member states … on the proposal.”
Commissioner Cheryl LaFleur said, “Of course the views of the states are very important,” adding that states can change grid operators if they prefer.
“We don’t assign you,” she said. “In some regions, the states are not unanimous on one solution, and it does allow the FERC to figure out what’s just, reasonable and nondiscriminatory using our own judgment.”
Commissioner Richard Glick stressed the importance of FERC developing a proposal that actually addresses resilience issues.
“It seems to me … that some RTOs are suggesting things that don’t necessarily [relate] to resilience,” he said.
‘Fresh Look’ at Pipeline Policies
The low cost and abundancy of natural gas also had regulators focused on pipeline infrastructure. Several FERC commissioners discussed McIntyre’s plan to review the commission’s 1999 policy statement on pipeline approval.
“It has been policy at the FERC not only since 1999, but prior to that, to ensure that no pipeline proposal is approved where there is not a demonstrated need for the project. What has evolved … is the standard for determining how that is measured and should it continue to evolve,” McIntyre said. “It’s time for us to dust that off and have a fresh look at it and see what changes, if any, are appropriate to that.”
He said FERC should take into account many variables, including environmental concerns and whether the commission should weigh how many contracts with a pipeline have been signed by affiliates of the applicant.
“They’re still independent market participants, but is that enough?” he said. “Should the regulator look at the stance in that sort of situation and say, ‘That doesn’t seem like a valid arms-length measure of pipeline need.’”
Glick said, “The commission’s kind of veered away from … its approach that it had taken in the past toward considering whether there’s a need for a pipeline.” He said it “seems to be backwards” that the commission has to provide the certificates necessary to access private land to do surveys necessary to determine where pipelines should go.
Chatterjee said he’s “strongly supportive” of reviewing the policy, is concerned about landowner issues and understands the “complex tension that exists.”
Bruce McKay, a senior energy policy director at Dominion Energy who spoke during a panel on pipeline infrastructure, said, “Increasingly, energy policy is being made on a project-by-project basis. The keep-it-in-the-ground movement … the strategy seems to have shifted to go after pipelines and transportation of energy as a way to change energy policy, as opposed to getting likeminded people elected or persuading those elected into office or in policymaking roles to change policy.”
He said that, like highways, the overall capacity of the nation’s pipeline system doesn’t address local constrictions.
“If you can’t get it where you need it when you need it, it becomes a real problem,” he said.
Kimberly Harris, CEO of Puget Sound Energy and chair of the American Gas Association’s board of directors, noted that the U.S. used 147.1 Bcf of gas on Jan. 1.
“We actually set the all-time record for the output of the natural gas system,” she said.
Two-Way Street on PURPA
The commissioners are also interested in reviewing how FERC handles PURPA.
“The question is whether there are steps at the FERC level that will improve the overall playing field of PURPA today,” McIntyre said. “The answer is probably ‘yes.’”
He indicated several issues to examine, including the project size necessary to be a qualified facility. He said calculation of the avoided-cost rate used for PURPA contracts “is still a very old-fashioned process, determined administratively state by state.”
A panel of the Committee on Electricity addressed PURPA issues, arguing that both sides of the issue take advantage of the law for their needs. Advocates for QFs said utilities fight accepting QF energy in favor of their own generation projects, while utilities said QF developers skirt rules to get their projects automatically approved, such as breaking them into smaller-sized units that are automatically accepted.
“The gaming of regulations goes both ways, and you expect that,” said Steve Thomas, an energy contract manager for paper company Domtar.
PURPA opponents contended the law requires utilities to pay for and accept energy production from QFs even if the utility doesn’t need the energy, which can create reliability and operational issues. Proponents say the rule helps QFs crack into markets and that utilities have the tools necessary to avoid paying for energy they don’t need.
“The problem is that utilities don’t want to ever stop buying,” said Todd Glass, an attorney representing solar developers. “They want their own generation. They want to continue building. They want to continue buying. They just don’t want to buy from QFs. … What you need to do is hold the utilities to the task of doing avoided cost. If you’re going to eliminate the ability for QFs to sell to them, you need to eliminate their own ability to self-build and buy for themselves too. You shouldn’t have it both ways: that the utility can get rid of the QFs and then just self-deal.”
Kendal Bowman, Duke Energy’s senior vice president of regulatory affairs and policy, said utilities can avoid taking on QF capacity by reducing their avoided-cost rates to zero — but they are still required to buy the energy as it’s produced.
“That is 70% of that avoided-cost payment,” she said. “Roughly 30% is capacity. The other 70% is energy.”
Montana Public Service Commission Vice Chairman Travis Kavulla said FERC has interpreted PURPA as requiring states to forecast utilities’ avoided-cost rates to set long-term QF contracts.
“This type of administrative pricing essentially requires states to guess at future market prices, allowing QFs to lock in rates that substantially overstate the actual avoided cost as it’s revealed in real time,” he said. “It’s not altogether clear whether a more competitive approach, if states were to embark on it, is legal and comports with FERC’s implementing regulations of PURPA. … It’s ironic that, in the context of a trendy, happening industry like renewables, we’re stuck debating whether or not they should rely on such an arcane crutch like PURPA.”
Glass said PURPA hasn’t solved the problems of getting small energy projects into large utilities.
“Where there is monopoly ownership of generation, transmission and distribution, the problems remain the same,” he said. “Yes, it’s an improvement, but [QF resources accounting for] 9% [of generation] is all we’ve gained in the last 40 years [since PURPA was enacted]. The rest of it is coal, gas, nuclear and the same hydro that existed in 1978. So, yes, we’ve made improvements, but have we achieved a diverse portfolio yet? I don’t think so. We have made strides, don’t get me wrong, in diversifying, but we’re not there yet.”
Thomas saw it both ways. He agreed that cogeneration facilities need the long-term assurance of contracts like PURPA to get approval to make the capital expenditures necessary to build the facilities. But he also supported not paying for more capacity than necessary.
“Certainly any gaming — somebody who can force a utility that doesn’t need to buy capacity or energy to buy capacity and energy — is not good,” he said. “But we do also support the idea that if I want to bring capacity and energy to your system, that it be fair in price.”
He credited PURPA for enabling combined heat and power and waste heat recovery facilities to exist.
“We self-fund our generators. We pay for them out of efficiencies for taking something that was going to go unused and turning it into electricity. I honestly don’t know that that ability would have been there without PURPA to try to, for lack of a better word, force utilities to look at allowing these extra generators,” he said. “It’s hard … to make the case at a new facility to put in the extreme capital cost for generation if we don’t know what the market’s going to be or if the market’s going to be pulled away from us. And PURPA, even if it’s not used, if it’s there, it gives us some [assurance] that we can build those assets.”
Thomas said the goal is to have it both ways.
“That’s what we’re looking for: the wisdom to reshape PURPA as needed to make sure customers don’t have to buy generation and energy that they don’t need, but that when there is a need or when that energy could be fit into a cost curve, that they be allowed to be there,” he said.
“During the 90s, I represented pulp-paper companies, steel companies, aluminum companies, developing PURPA projects. Utilities hated us. Even more than they hated us, they hate renewables now. To have a revisionist history where utilities have always liked you guys, they don’t. They don’t like you now, they didn’t like you then, they’re not going to like you in the future if you’re the last man standing,” Glass said.
Panelists discussed several ongoing initiatives to revise the rules. NARUC has sent a request to FERC to reconsider how it handles PURPA. U.S. Rep. Tim Walberg (R-Mich.) has also introduced a bill that would allow state regulators to assume some PURPA decision-making currently held by FERC. Kavulla testified on behalf of NARUC in support of the bill before a congressional subcommittee in January. (See House Panel Considers Bills on PURPA, LNG Exports.)
Thomas warned that Walberg’s legislation would substantially deter cogeneration projects.
“There’s a lot of energy that would go to waste if that were to happen,” he said.
AUSTIN, Texas — The Public Utility Commission of Texas last week hinted it may be near a decision on Lubbock Power & Light’s proposal to move 470 MW of its load from SPP to ERCOT.
During their Feb. 15 open meeting, the regulators asked an administrative law judge to rule on some remaining questions and submit a final order before their March 8 meeting (Docket No. 47576).
Chair DeAnn Walker suggested the ALJ avoid a detailed discussion of exit fees and save that for a staff rulemaking. LP&L committed to paying an exit fee in a settlement agreement with intervenors, but as Walker pointed out, the utility has also chosen to participate in ERCOT’s competitive retail market.
“If they make that choice, they’re not going to be able to leave” ERCOT’s competitive market, she said.
Walker said the order should assign LP&L and Sharyland Utilities — which has proposed a $247.5 million, 345-kV project that overlaps with the facilities necessary to integrate Lubbock’s load into ERCOT — to coordinate the respective parts of the system for which each would be responsible.
LP&L workers | LP&L
“If they’re unable to agree, they will have to file a proceeding here,” Walker said.
LP&L officials, who had expected a final order, were nonetheless thrilled with the PUC’s action. In a statement, David McCalla, LP&L’s director of electric utilities, called it “the most important milestone to date in our case to join ERCOT.”
Lubbock’s power needs are currently met through two long-term contracts with Southwestern Public Service, one of which — 470 of 600 MW — expires in June 2021. LP&L says moving from SPP to ERCOT and allowing retail competition will give its customers access to a “diversified portfolio of reliable and affordable Texas power for generations to come.”
The utility reached a settlement agreement with SPS, PUC staff, the Office of Public Utility Counsel and other consumer groups last month. The Lubbock City Council and LP&L’s board of directors approved the settlement, which the utility filed with the PUC on Feb. 8. (See Lubbock Council, Utility Board Approve LP&L Settlement.)
LP&L has agreed to pay $22 million annually over five years to compensate ERCOT’s transmission customers for additional infrastructure costs, and to also make a one-time $24 million payment to SPS for previous infrastructure costs.
While thanking everyone for their efforts in reaching a settlement, Walker couldn’t resist needling LP&L attorneys Lambeth Townsend and Chris Brewster. “It would have been nice if it had been before the hearing,” she said, referring to the commission’s two-day hearing in January. (See Texas Regulators Noncommittal After LP&L Hearings.)
The commissioners discussed the need for a rulemaking on future transfers. Rayburn Country Electric Cooperative, which sits on the ERCOT-SPP seam in East Texas, has proposed transferring load and transmission facilities into ERCOT, while Walker alluded to holding a recent discussion about another transfer “that’s on the horizon.” (See “ERCOT, SPP Agree to Rayburn Country Migration Studies,” Public Utility Commission of Texas Briefs: Aug. 31, 2017.)
“I personally don’t think we learned enough with this [transfer] to get specific,” Commissioner Arthur D’Andrea said in agreeing to the need for the rulemaking. “I wonder if we can’t get into the weeds on some of the rules.”
The commission also asked staff to open a project within the docket that would require LP&L to file quarterly updates on the transition’s status.
Blocked by regulators from moving its ailing coal-fired Pleasants Power Station into the rate base of a subsidiary, FirstEnergy announced Friday it will shut the plant down instead. The company said in a news release that the 1,300-MW plant in Willow Island, W.Va., will be sold or closed on Jan. 1, 2019.
The plant has been at the center of a conflict between the company and state consumer advocates since Monongahela Power, a regulated FirstEnergy subsidiary, filed a plan in March 2017 seeking approval to acquire the station from another subsidiary, Allegheny Energy Supply. Mon Power selected the plant after issuing a request for proposals for generation.
FirstEnergy’s coal-fired Pleasants Power Station in West Virginia
Soon thereafter, the West Virginia Public Service Commission approved the sale, but with restrictions that FirstEnergy felt were too onerous to proceed.
“Those conditions, combined with the FERC rejection, make the proposed transfer unworkable,” the news release said.
FirstEnergy CEO Charles Jones said the company would continue to look for a buyer while it prepares for deactivation. The closure will affect 190 jobs, according to the release. Following the closure, the company will control 14,795 MW of generation from coal, nuclear, natural gas and renewables across Ohio, Pennsylvania, West Virginia, New Jersey, Virginia and Illinois.
The transfer to Mon Power was one of many avenues FirstEnergy has tried to offload its merchant generation. Jones has warned that its competitive generation subsidiary, FirstEnergy Solutions, will likely go bankrupt and has repeatedly confirmed plans to return FirstEnergy to regulated operations, where its investments will receive defined rates of return. (See FirstEnergy Selling Merchant Fleet Despite NOPR.)
PJM spokesman Ray Dotter on Monday said it’s “way too soon to be able to say” whether Pleasants would be offered a reliability-must-run contract. “First, the reliability analysis must be completed. If the analysis indicates reliability issues, the owner could be requested to consider staying online until transmission upgrades were completed. If the owner agrees, it would go to the FERC to request an RMR rate.”
Ex Parte Controversy
FERC’s Jan. 12 ruling blocking the plant sale came after Commissioner Neil Chatterjee reported that lawyer William S. Scherman attempted to privately lobby him on FirstEnergy’s behalf.
Chatterjee said Scherman called him the day before the ruling “indicating his concern that the commission would shortly issue an order adverse to the interests of Monongahela Power.”
FERC Chairman Kevin McIntyre declined to say last month whether the commission would investigate who may have leaked information on the order to Scherman, who has represented FirstEnergy in the past. McIntyre called Scherman “a good friend” and “a terrific lawyer.” (See McIntyre: Won’t Commit to Probe Leak to ‘Good Friend’.)
At a press conference following last week’s commission meeting, McIntyre told reporters he had spoken with FERC General Counsel James Danly about the matter.
“I directed our general counsel to take the matter up with our designated agency ethics official to help us with two things,” McIntyre said. “No. 1, to ensure that our annual ethics training properly address the issue of ex parte communication restrictions. Second, to ensure that it properly address the very important principle of ensuring no improper sharing of nonpublic information with regard to work in the commission. Those steps have been taken. I’m confident that they’re the right steps.”
Asked if it sent the right message for him to call Scherman a “friend,” McIntyre responded: “It wasn’t to send any signal along those lines. Really, just to ensure that our systems are properly functioning. I’m confident that they did in fact function properly.”
AUSTIN, Texas — The Public Utility Commission of Texas postponed until March a decision on whether to remove reliability unit commitments (RUCs) from ERCOT’s operating reserve demand curve (ORDC), which creates a real-time price adder to reflect the value of available reserves.
The delay will allow the commission to gather more feedback from ERCOT on the effects of removing RUCs before heading into the summer months. The commissioners are reluctant to make additional changes that may affect prices, following a recent wave of coal retirements that halved the ISO’s planning reserve margin to 9.3%.
“We are prepared for what the summer is going to bring, which is high prices,” Commissioner Brandy Marty Marquez said. “The question we’ve got to ask ourselves is what are the signals we want to send going into the summer? We’re going into a summer where people are going to be potentially paying a lot more. Will we make changes that have another factor of costs layered onto that?”
Walker checked her understanding of ERCOT’s RUC process with Kenan Ogelman, the ISO’s vice president of commercial operations. He told her that ERCOT seldom issues RUCs during the summer, and that its operators continue to minimize their use.
“We might RUC something for capacity initially, but it’s also ultimately the solution for a local issue,” Ogelman said. “They tend to intertwine somewhat, so we’re looking at how we might differentiate those.”
Walker said she didn’t want to make any “big changes” going into the summer but also said she believes removing RUCs from the ORDC is the “right decision.” Ogelman responded that the ISO could provide further information to the PUC for its next meeting and still gain approval from its board of directors by July.
That gave comfort to the commissioners, who seem to be leaning toward removing RUCs from the ORDC. Whether it happens before this summer or the next, remains to be seen.
“I think it’s the right policy … but we’re going into a situation that’s new,” Marquez said. “Any changes we make at this point … will have an impact on ratepayers. We just don’t know exactly what that’s going to be. Do we do something at this point that turns up the heat on this, or do we let ourselves go through the summer, and then have more information on it?”
“This is a real opportunity to see how the ORDC works, and we should take it,” Commissioner Arthur D’Andrea said. “That said, removing the RUC from the ORDC makes sense to me, but not if the retail electric providers start screaming bloody murder. My understanding is this could get done rather painlessly.”
Catherine Webking, representing the Texas Energy Association for Marketers, told the commissioners her group would want to see further “quantification” from ERCOT before their next meeting.
“We would not be screaming bloody murder,” she said, “but we do think it violates the concept of giving time to make adequate changes in [power] contracts.”
Utilities Propose Mechanism to Pass on Tax Savings
The PUC continues to deal with the fallout from the reduction in the federal income tax rate and how those savings should be passed on to consumers.
Staff told the commissioners they have been meeting with investor-owned electric utilities, who have all proposed using any combination of three ratemaking mechanisms to share their tax savings: revising their interim transmission cost-of-service (TCOS) and/or their distribution cost recovery factor (DCRF), or by using a credit rider adjustment.
“All companies have indicated they will use one or more of those methods, and all plan to do it in a very timely manner,” reported staff’s Darryl Tietjen. By rule, utilities must file their requested DCRFs by April 1.
Tietjen noted Houston’s CenterPoint Energy had already filed a letter detailing terms of a settlement it had reached with staff and other parties. CenterPoint committed to a series of filings that will include revisions to its TCOS, a DCRF application and a base rate case, to be filed no later than April 2019.
Texas Sen. Kelly Hancock (R), chair of the Business and Commerce Committee, has also filed a letter with the commission asking all retail electric providers (REPs) to make a public commitment that they will pass tax savings on to their consumers.
“Any deviation from that practice would result in legislative action to clarify the regulatory scope of the commission” during the Legislature’s 2019 session, Hancock warned.
Walker asked staff to work with the REPs and “see if there’s some way to accomplish what Sen. Hancock has asked us to look at.”
The commissioners also amended a previous order on the subject, deleting a reference to carrying changes on the balance of excess accumulated deferred federal income taxes (Docket No. 47945).
Staff Opens Battery-Storage Rulemaking
Saying it did not have “sufficient information” to rule on American Electric Power’s request to connect a pair of utility-scale battery facilities to the ERCOT grid, the PUC asked staff to open a project that addresses “necessary policy issues” and develops an “appropriate regulatory structure” through a future rulemaking (Docket No. 46368).
“Only after facts are fully developed will the commission be in a position to resolve relevant policy issues and design the appropriate regulatory framework with proper standards,” the commissioners said in their order. New rules are necessary “to define the appropriate manner in which energy storage devices are used before the use of energy storage devices can move forward.”
AEP had proposed installing separate 1-MW and 50-kW battery facilities in two rural Texas areas, setting them to automatically discharge during an outage or to serve additional loads. It has proposed the energy be accounted for as “unaccounted-for energy (UFE),” which ERCOT defines as the difference between the system’s total generation supply and the total system load plus losses.
Consumer organizations and market participants both opposed AEP’s request, arguing that allowing the assets to be included in its regulatory base would harm competition. (See PUCT Considering Rulemaking over AEP Battery Proposal.)
Commission Approves Investment Firm’s Acquisition of Calpine
The commission, as part of its consent agenda, approved Calpine’s request to be acquired by private investment firm Energy Capital Partners (ECP) in a $5.6 billion deal (Docket No. 47607).
Commission staff found no market power concerns, saying Calpine and its subsidiaries will own or control about 12 GW of ERCOT’s installed capacity upon the transaction’s consummation, or almost 13% of ERCOT’s total — below the 20% cap.
Under the merger agreement’s terms, VoltSub, an ECP subsidiary, will merge with Calpine, which will continue as the surviving entity.
Calpine announced it was going private last August. New York regulators and Calpine stockholders have also approved the transaction, which is targeted to close in the first quarter of 2018. (See Calpine Going Private in $5.6B Deal.)
FERC dismissed concerns from several stakeholders last week in approving the Ohio Valley Electric Corp.’s integration into PJM (ER18-459, ER18-460).
The commission said OVEC and PJM had satisfied the Operating Agreement requirements for integrating the company, rejecting objections by stakeholders including American Municipal Power, the Ohio Consumers’ Counsel and the Public Utilities Commission of Ohio. The protesters expressed concern that OVEC’s integration will result in significant upgrade costs and increase the existing generation oversupply without providing more load for PJM generators to serve. (See OVEC Integration not up for Debate, PJM Says.)
The commission also accepted grandfathering of several power agreements and delivery commitments.
OVEC, which is headquartered in Piketon, Ohio, owns 2,200 MW of generation capacity but will have no load after a U.S. Department of Energy contract ends sometime before 2023. The company was created in 1952 to service a uranium enrichment plant near Piketon that ceased operations in 2001. The department ended the 2,000-MW contract in 2003 but maintains a load that can be 45 MW at its maximum but is generally less than 30 MW.
The company’s two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — are already pseudo-tied into PJM, and its eight “sponsors” can sell their portions of the output into the RTO’s markets. The generation would become internal to PJM following membership, eliminating the pseudo-ties.
Clifty Creek Power Plant Complex | Crowezr
The commission said it didn’t buy members’ arguments that a cost-benefit analysis should be required prior to integrating OVEC — a request which the OCC also made separately to PJM — because there’s no precedent for it and the benefits to consumers from RTO membership “outweigh” integration costs. The commission said those benefits are “increased efficiency for transmission planning and generation investment, reduced transaction costs, improved grid reliability, limited discriminatory practices and improved market operations.”
It also said concerns about future costs aren’t warranted because those costs will be allocated based on PJM’s Tariff and OVEC’s sponsor companies will continue to pay for OVEC’s share. The order noted that PJM’s studies indicated no transmission upgrades will be required to integrate OVEC. “With the exception of a single deliverability violation, which OVEC has committed to remedy, the existing equipment and facilities are adequate,” the commission said.
PJM’s Independent Market Monitor had raised concerns about OVEC’s aging plants becoming eligible for reliability-must-run contracts if they decide to shut down, but the commission said the issue is beyond the scope of the integration request.
WASHINGTON — The cybersecurity expert whose firm discovered the malware that caused blackouts in Ukraine in 2016 told state regulators that hackers targeting the U.S. electric industry are growing more numerous and more skilled.
“There are five dedicated teams targeting infrastructure sites in North America, including eight different campaigns targeting sites,” Robert M. Lee, CEO of cybersecurity firm Dragos, told the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Feb. 11. “This is an extreme uptick.”
In June, Lee’s company identified malware it named CrashOverride as the likely cause of a disruption in December 2016 that cut one-fifth of Kiev’s power consumption for an hour. (See Experts ID New Cyber Threat to SCADA Systems.)
The attack occurred about a year after the December 2015 attack on Ukraine — the first time hackers had taken down a portion of the power grid. The 2015 attack used the BlackEnergy program, which highjacked the supervisory control and data acquisition (SCADA) systems, taking control of operator workstations and locking the operators out.
CrashOverride — which can control circuit breakers without any manual involvement — takes advantage of the simplicity of SCADA. “CrashOverride was just knowledge of the 2015 attack getting codified in malware to make it scalable,” Lee said. “A lot of times we tell ourselves, ‘There’s computer vulnerabilities; if we patch the computer vulnerabilities, we’re OK.’ But that’s not the actual risk. … [The 2016 Ukraine attack] was just adversaries learning the industrial systems and using them against themselves — almost becoming malicious insiders even though they were remote.”
The 2016 outage lasted only an hour. But, Lee said, CrashOverride is still dangerous because it “can work without any modification across all of Europe, most of the Middle East and most of Asia.”
The malware is an illustration of the increasing sophistication of hackers, Lee said. As recently as 2014, he said, there were only two campaigns against infrastructure sites. 2015 saw not just the first attack on Ukraine but also a cyberattack that caused physical damage at a steel mill in Germany — only the second attack to produce such results, after the Stuxnet attack on Iran’s nuclear centrifuges.
Last year, the first known malware specifically targeting industrial safety systems was identified, Lee said. The malware, which targets Schneider Electric’s Triconex safety instrumented system, was deployed against at least one victim in the Middle East. “It was going after safety systems in oil and gas production facilities. The only purpose of a safety system is to protect human life. If you go after it willfully … you are either intending to kill people or you’re just OK with doing so.”
Lee said grid operators and other industries face two strategic challenges. “We don’t truly understand or appreciate our industrial threat landscape,” he said. “So, we get a lot of best practices or compliance standards written off of business network security, not industrial network security to address the real risk.
“The second challenge is there’s not a lot of people who are industrial cybersecurity experts. The Department of Homeland Security puts that at around 500 people in North America … so you’re not going to scale that across the industry.”
Lee said small electric cooperatives and water utilities may be particularly vulnerable because of their limited staffs. He said his company has done “charity” work for one small water utility where “the one IT guy actually mows the lawn on Fridays.”
Tim Roxey, NERC’s chief security officer, said there are fewer than 500 people who have the necessary cybersecurity expertise and understanding of both NERC’s Critical Infrastructure Protection standards and federal government rules.
“You don’t find a whole lot of beer conversations around the bar about the Administrative Procedures Act, and yet these things are fundamental … to how we actually … develop the standards, implement the standards [and] enforce the standards,” he said.
There is some good news on that front, however. In an earlier presentation at the NARUC meeting, Dennis P. Gilbert Jr., Exelon’s chief information security officer, reported on his company’s adoption of the National Initiative for Cybersecurity Education (NICE) Workforce Framework. Developed by the National Institute of Standards and Technology, the program provides organizations with a common lexicon for describing cybersecurity careers by category, specialty area and work role. It involves creating new job titles and performing a market salary assessment.
Gilbert said Exelon was happy to reward many of their cybersecurity team members with 10 to 35% pay raises, citing better morale and a lower attrition rate of 5% — reducing the costs of having to recruit and train new workers in the “high demand, low density” career field.
Jim Hempstead, managing director of Moody’s Investors Service’s Global Infrastructure Finance Group, who shared the panel with Lee and Roxey, explained how cyber risks figure in credit rating agencies’ evaluation of companies’ ability to pay their debts.
“We do not explicitly incorporate cyber risks into the credit analysis for the utility industry or for any of the other” industries, Hempstead said. “The transparency and disclosure around cyber risks are unreliable. There’s just not enough disclosure as to what the events are. And there’s not enough disclosure as to what is actually happening behind it.”
Instead, Hempstead said, Moody’s conducts scenario analyses that treat cyberattacks like extreme weather — a low-probability, high-impact event.
“We have seen over and over again utility companies that are able to absorb the impact of a severe event that in many instances has significant financial consequences, but the company is still able to right itself and put itself back on track.
“Now that means the cyberattack [modeled] is not a permanent destruction of critical infrastructure,” Hempstead added, distinguishing it from the dire scenarios painted by Ted Koppel in his controversial 2015 book “Lights Out.” (See Critics: Koppel Doomsday Scenario Ignores Prep.)
“If Ted Koppel is correct and everything east of the Mississippi is affected by cyber for 18 months, that’s outside the bounds of what we’re incorporating in our analysis,” Hempstead said. “But because utilities are viewed by Moody’s as critical infrastructure assets, we believe there will be an extraordinary government intervention to assist the company in putting itself back on track.”
Hempstead said Moody’s is concerned that the cybersecurity regulations for the utility industry “could create a culture of compliance where the defenses are relaxed because the compliance check boxes are getting checked. That’s, we don’t think, the right mentality. Cyber risk is an enterprise risk issue and therefore it resides at the board of directors. And we are very encouraged at how many boards of directors in the utility sector are very focused on cyber.”
Lee said some of his customers have been reluctant to embrace innovation for fear of being found in violation of reliability standards. Others express concern over how Dragos’ subscription-based services will impact their bottom lines. “Right now, one of the biggest pushbacks I get from a lot of my customers across the utility industry is, ‘Hey is there any way we cap ex this?’” he said. “We have to figure out how to make sure that the [security effort] that is already moving in the right direction is not hampered by the way we want to do accounting.”
In an earlier presentation, Bill Lawrence, director of NERC’s Electricity Information Sharing and Analysis Center (E-ISAC), shared lessons learned from GridEx IV exercise in November, which simulated physical and cyberattacks on the electric system. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.) E-ISAC works with the Department of Energy and the Electricity Subsector Coordinating Council (ESCC) to inform the industry about physical and cyber threats.
“The scary thing is … everything we come up with [as an attack scenario] has happened somewhere in the world — about 99% of our entire scenario [has happened],” Lawrence said. “So, things with drones, things with modular malware, things with drains on resources in both computer and physical security.”
A public report on GridEx IV is due at end of March. A meeting will be held in November to plan for GridEx V, to be held in 2019.
ISO-NE on Thursday defended its proposed two-stage capacity auction, responding to criticism by its External Market Monitor and others.
In its Feb. 13 response to protests, the RTO asked the commission to approve its Competitive Auctions with Sponsored Policy Resources (CASPR) program, saying the Monitor’s “proposed cure would be worse than the disease” (ER18-619). Monitor David Patton filed a protest Jan. 30 saying that he supports “the objective and approach” of CASPR but that the RTO’s proposal has a “critical design flaw” that will result in “inefficient investment and retirement decisions and over the long term … raise costs substantially to New England’s customers.”
Also filing protests in response to the Jan. 8 CASPR filing were Massachusetts Attorney General Maura Healey; municipal utilities (New England Consumer-Owned Systems); Connecticut; the Natural Gas Supply Association; a coalition of environmental groups (Clean Energy Advocates); the New England Power Generators Association; and several merchant generators. (See CASPR Filing Draws Stakeholder Support, Protests.)
The CASPR proposal grew out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, launched in August 2016 to address state regulators’ concerns about ratepayer costs associated with policy-driven resources and generators’ fears that out-of-market procurements of renewable generation would suppress capacity prices.
Under ISO-NE’s proposal, it would clear the Forward Capacity Auction as it does today, applying the minimum offer price rule (MOPR) to new capacity offers to prevent price suppression. In the second Substitution Auction (SA), generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR. The proposal would phase out the current Renewable Technology Resource (RTR) exemption, which has allowed ISO-NE to clear 200 MW of renewable generation in its capacity auction annually (to a maximum of 600 MW) without regard for the MOPR.
ISO-NE’s External Market Monitor included this example in its protest, saying excluding new conventional resources from the substitution auction (left) would clear only 400 MW of sponsored resources, with three existing resources retiring and sponsored resources foregoing $31.2 million in capacity payments. Under the Monitor’s proposal (right) 500 MW of sponsored resources would clear and only one plant would retire. Sponsored resources’ foregone capacity payments would total only $2.7 million. | Potomac Economics
Bad Cure
ISO-NE said it prohibited new conventional resources from participating in the secondary auction “to protect the Forward Capacity Market’s ability to guide competitive and cost-effective entry and exit decisions to maintain resource adequacy.”
But Patton’s Jan. 30 filing said the exclusion of new conventional resources from the SA will cause “new resources to clear and enter when they are not economic or needed and existing resources to retire that are economic to continue operating and whose costs of remaining in operation (i.e., going forward costs) are much lower than the entry costs of new resources that are entering.”
Patton would allow new conventional resources to clear through the SA “so they may be efficiently displaced by the sponsored resources.”
“This was a component of the ISO’s original proposal, but it decided to alter its proposal by excluding the new conventional resources from the Substitution Auction,” Patton wrote. “By doing this, the supply and demand (and prices) that will determine when a new conventional resource enters will ignore supply from the sponsored resources.”
The RTO retorted that “the EMM’s proposed cure would be worse than the disease” by creating “more, and more significant, problems than the overbuild problem it seeks to fix.”
One such problem would be fictitious entry, in which developers with no intention of building generation enter the FCA just to secure the severance payment in the second auction. The EMM’s fix? New conventional resources that are displaced by a sponsored resource would receive no payment.
The RTO said that could scare off new competitive generation, resulting in high capacity clearing prices — the “price blowout problem.”
Patton said that fear is “misplaced.”
“The risk described by the ISO is a risk that is common to all investment decisions and is efficient for the investor to consider in making its investment decision. Any time new resources are entering the market, whether they are sponsored resources or competing conventional resources, this will reduce the expected profitability and increase the risk to subsequent investment,” he wrote.
The EMM would modify the MOPR applied to sponsored resources in the primary FCA so that they can clear at a moderate price, potentially replacing the market-based clearing price with an administratively determined one.
“In addition to its complexity, this multilayered solution is both unfair and ineffective,” the RTO said.
Impossible to Win?
“In this situation, the conventional new resource has responded to the market’s price signal and succeeded in securing a capacity supply obligation (CSO) because it was willing to sell its capacity in New England at the primary auction’s clearing price,” the RTO said. “To strip such a resource of its award without compensation would alter the meaning of the clearing price, as a high price no longer would serve its fundamental purpose as a market signal to encourage commercial investment.”
The EMM’s proposal makes it impossible to “win” an auction, and the outcome differs fundamentally from “the outcome of a normal competitive auction in which an investor fails to clear because its offer price exceeds the market’s clearing price,” the RTO said.
ISO-NE also objected to the EMM’s proposed “price-setting by administrative dictate,” which it found “problematic, both practically and philosophically.”
Practically, the EMM methodology would create reliance on a predetermined estimate that may or may not reflect the true net cost of new entry (CONE), and “to the extent that number is wrong, FCM’s clearing price may be inflated or deflated,” the RTO said.
Philosophically, the EMM’s proposal would result in an outcome largely dependent on administrative parameters. The outcome, like that of the RTR exemption that CASPR seeks to replace, “ameliorates system overbuild but undermines the competitiveness of capacity prices,” ISO-NE concluded.
Applying the Monitor’s proposal to FCA 12 would have resulted in total costs of $4.15 billion, an increase of $908 million, or 28%, the RTO said.
“There can be no perfect solution that completely meets the objectives to maintain competitive pricing and accommodate state-sponsored resources,” ISO-NE said. “When required to trade between these competing objectives, the ISO prioritizes competitive prices.”
RTR Exemption
The RTO also defended its proposal to phase out the RTR exemption, calling it a “blunt instrument.”
The conditions that made the RTR exemption just and reasonable upon its adoption will no longer exist going forward, the RTO said: “Instead, load growth has slowed, the region has excess capacity, and, most significantly, the states have announced plans to contract for substantial amounts of sponsored capacity.”
NextEra Energy and NRG Energy insisted that the commission eliminate the RTR exemption immediately, saying it suppresses prices. CASPR would phase out the exemption by allowing the exempt megawatts that have accrued in earlier auctions — currently 481 MW — to be used over the coming three years through FCA 15.
NextEra argued that the three-year phase-out made no sense because the conditions that supported the exemption no longer exist. The RTO answered that a measured transition was necessary to maintain investor confidence and lower costs over the long term. It noted that the commission has accepted similar transition mechanisms in other capacity market proceedings.
Attorney General Healey opposed CASPR as not allowing “for any regular or reliable integration of sponsored policy resources” into the FCM. She recommended a mechanism like the “backstop” proposed by the New England States Committee on Electricity, which would guarantee entry of up to 200 MW of sponsored policy resources annually regardless of whether they were matched by retirements.
She also suggested the commission could remand the proposal to the RTO with an order to reinstate the RTR exemption.
The RTO said that, given current market conditions, a 200-MW RTR exemption would depress FCA clearing prices by up to 87 cents/kW-month. Continuing the RTR exemption or adding a backstop would undermine CASPR “because no sponsored policy resource would elect to sell capacity at a low price in the Substitution Auction when it could instead receive the higher primary auction price through the exemption,” ISO-NE said.
The CAISO Board of Governors last week enacted new governance policies and named Governor David Olsen as chairman. It also reviewed the ISO’s policy roadmap for 2018.
In a teleconferenced meeting Thursday, the board enacted a new process whereby governors will hold yearly elections for chair. The five-member board voted to replace sitting Chair Richard Maullin with Olsen, who was originally appointed to the board in 2012 by Gov. Jerry Brown.
Governor Angelina Galiteva said that with CAISO involved in more regional matters and the Western Energy Imbalance Market (EIM), the board felt members should have the opportunity to participate as chairs and share some of the growing workload. The board went through an analysis to study best practices, she said.
“This is something we thought over and talked about for quite a while,” Galiteva said. The board elected her to the newly created position of vice chair, nominated by Governor Mark Ferron and seconded by Governor Ashutosh Bhagwat.
“We are entering a period where there could be some rapid change we are part of or instrumental for,” Maullin said, as other board members thanked him for his service in his role. Maullin’s term on the board ended Dec. 31, and he said remaining on the board depends on the California State Senate, which confirmed him as chair in July 2015. He was reappointed by Brown in January 2015.
Cook Briefs Board on 2018 Roadmap
CAISO Director of Market and Infrastructure Policy Greg Cook briefed the board on the 2018 Policy Initiatives Roadmap and Annual Plan, saying the presentation to the board represents the final step in the implementation process.
In January, Cook briefed the EIM Governing Body on the plan, which includes a proposal to extend the ISO’s day-ahead market to the EIM. (See CAISO Plan Extends Day-Ahead Market to EIM.) Each balancing authority area would retain reliability responsibility, and states would retain control over integrated resource planning. Transmission planning and investment remains with each BAA and local regulatory authority.
Cook shared some of the tasks associated with the day-ahead market extension, including the alignment of transmission access charge paradigms to ensure EIM entities recover transmission costs consistent with the existing bilateral network, and consistent billing determinants across the day-ahead market footprint for market efficiency. There will also be distribution of congestion rents collected through the day-ahead market and a day-ahead resource sufficiency evaluation, among other requirements.
Keith Casey, the ISO’s vice president of market and infrastructure development, told the board that implementing the day-ahead across the EIM will provide additional benefits, but it “certainly will fall short of the full benefits we would get with full participation under a regional construct.” These would include efficiency of a single balancing authority over a larger footprint, as well as transmission planning and resource adequacy benefits.
“We believe it has important benefits … but I do want to stress it will fall short of the full integration benefits,” Casey said.
PG&E Continues Criticism of RMRs
During a public comment period, Eric Eisenman, director of ISO relations and FERC policy for Pacific Gas and Electric, told the board that PG&E has no issue with anything in the roadmap but that addressing the increasing use of reliability-must-run designations (RMRs) and the capacity procurement mechanism (CPM) is the utility’s “highest priority.” He reminded the board of the “robust discussion” it had over RMRs at its November meeting when the designation of the gas-fired Metcalf Energy Center was approved. (See Board Decisions Highlight Market Problems.)
“PG&E continues to be very concerned about a slew of RMRs for 2019 that would be designated later this year,” Eisenman said. “But at this point, we just don’t know what is going to happen.” He urged CAISO to implement more extensive “Phase 2” changes in its RMR/CPM initiative in time for 2019 designations. The ISO has indicated it only intends to address must-offer requirements for RMR and CPM units in that time frame.
Casey said the ISO is looking at transmission alternatives to prevent situations that might otherwise lead to RMRs, including working with PG&E to address “low-hanging, fast upgrades” in the subarea where the Metcalf plant sits. The improvements would alleviate about 600 MW of local capacity requirements and are included in a transmission plan due to be finalized in March, he said.
“There is much we can do — we have a great deal of flexibility with the transmission plans to do those types of studies,” but it would be challenging to complete the improvements by fall 2019, he said.
“We share PG&E’s urgency about getting after these RMR reforms,” Casey said.
CAISO is in the midst of developing a package of enhancements to the RMR/CPM process, which is proving to be a contentious proposal among market stakeholders. (See CAISO, Stakeholders Debate RMR Revisions.)
FERC on Thursday approved a package of modifications to improve market efficiency developed by CAISO for the Western Energy Imbalance Market (EIM). It also issued several other decisions related to Western states and energy markets.
The commission said the EIM measures would improve efficiency by automating manual processes, providing greater transparency into bilateral transactions and enabling increased participation in both the EIM and CAISO.
The approved changes include automated matching of import/export schedule changes between resources inside and outside the EIM, as well as the ability to automate changes to mirror system resources at intertie scheduling points between CAISO and an EIM entity (ER18-461).
“We find that the automated matching and the automatic mirroring functionalities will result in more efficient EIM market outcomes by automating manual processes that are prone to errors and better maintain balance between resources and load following intertie schedule changes,” FERC said.
The EIM Governing Body approved the package of changes in November, after CAISO had scaled down the initiative based on consultations with stakeholders. (See EIM Governing Body Approves ‘Consolidated’ Initiatives.) The changes also facilitate bilateral settlements and improve the market’s modeling accuracy by expanding the functions of non-generator resources.
CAISO had requested approval of the measures by Feb. 15 to allow for the participation of Powerex and Idaho Power in the EIM on April 4.
Deseret Earns MBR Authority
The commission last week also approved Deseret Generation & Transmission Co-operative’s updated market power analysis for the Northwest region, granting the utility market-based rate authority effective Sept. 12, 2016. Utah-based Deseret became a public utility in 1996 after paying off its debt related to rural utility service (ER16-2186).
Deseret owns the 458-MW Bonanza coal-fired plant and a 25% interest in the 430-MW Hunter 2 coal-fired unit, both in the PacifiCorp balancing authority area.
FERC Approves PG&E/Port of Oakland Agreement
The commission also approved an interconnection agreement between Pacific Gas and Electric and the Port of Oakland but suspended the agreement and subjected it to hearing and settlement judge procedures (ER17-2536).
The Port of Oakland is a major container shipping facility and a municipal electric supplier.
The port acts a municipal electricity supplier that serves customers located at the Oakland International Airport, which it owns and operates, using PG&E’s transmission and distribution facilities.
Last year, the port submitted an application to convert its Cuthbertson substation from retail service to wholesale interconnection service under PG&E’s transmission owner tariff, but PG&E identified an issue with the tariff based on the substation’s power factor, which it said has to be resolved before it can provide wholesale service.
The port contends that PG&E’s sales for resale to it are subject to FERC jurisdiction and that it is concerned about provisions in the interconnection agreement referring to matters under the jurisdiction of the California Public Utilities Commission. The port argues that PG&E is attempting to “improperly impose” CPUC-jurisdictional exit fees on it and protests language describing the change to wholesale service as a notice of departure from PG&E, subjecting the port to departing load fees.
The port also contests that certain aspects of the agreement are unreasonable and unduly discriminatory compared with other PG&E interconnection agreements.
FERC set a public hearing subject to settlement procedures to be held within 15 days.
GridLiance Rehearing Request Rejected
FERC rejected GridLiance West’s rehearing request contending the commission erred when it failed to approve the company’s proposed use of an actual capital structure related to incentive rates for facilities it sought to acquire from Valley Electric Transmission Association (ER17-706). GridLiance West said the proposed capital structure was comparable to similarly situated transmission companies.
In its order denying rehearing, the commission said it made no final determination regarding the proposed capital structure but “found that its preliminary analysis indicated that the proposed TO Tariff had not been shown to be just and reasonable and raised issues of material fact that could not be resolved on the record before the commission.”
Idaho Commission Complaint Headed to Court?
FERC also declined to act on a petition for enforcement filed by Franklin Energy Storage against the Idaho Public Utilities Commission (EL18-50, et al.). The company argued the state commission had improperly classified its energy storage facilities as solar qualifying facilities, preventing them from being eligible for the PUC’s stated electricity rate under the Public Utility Regulatory Policies Act. The rate is available to non-wind and non-solar QFs of an average capacity of 10 MW or less.
The decision will allow the company to bring an enforcement action against the Idaho commission in the appropriate court, FERC said.
