Fourth-quarter profits of $99.6 million ($0.56/share) weren’t enough to offset Energy’s losses for the year, the company reported last week.
Entergy lost $176.6 million (-$0.99/share) in 2015, compared to $940.7 million in earnings in 2014. Much of the loss was driven by its wholesale electricity business, Entergy Wholesale Commodities (EWC), which experienced a 46% drop in operational earnings.
Entergy CEO Leo Denault noted that the company’s results are “reflecting the changes in strategic direction for the EWC business.” Those changes included deciding to shut down the Vermont Yankee, Pilgrim and FitzPatrick nuclear stations. Vermont Yankee closed at the end of 2014, while the company announced late last year it would close the other two.
“The most significant factor was lower wholesale prices,” CFO Drew Marsh said. “The nuclear fleet revenue was $44/MWh this quarter, down from $54 in 2014, excluding Vermont Yankee. Closure of VY contributed 5 cents to the decline.”
“We took steps to reduce volatility and gain clarity on the future of the business. Closing Pilgrim and FitzPatrick was not the path we wanted to take,” Denault said. “After pursuing many alternatives, they ultimately were the only options remaining for us. We know they are tough decisions for those involved and we are committed to supporting our employees who work at these plants and their communities throughout this difficult transition.”
Denault said the company has yet to commit to a mid-year refueling at Pilgrim, which will have a large effect on future costs and generation output there, and possibly the closing date.
He also said the company is committed to building new natural gas-fired generation, including a 980-MW plant in Montz, La., as well as the purchase of the Union Power Station, a 1,980-MW near El Dorado, Ark.
Ameren last week reported fourth-quarter earnings of $29 million ($0.12/share), down from $48 million ($0.20/share) in the same period of 2014. Ameren’s 2015 net income totaled $630 million ($2.59/share) compared with 2014’s $586 million ($2.40/share).
Operating revenues for the fourth quarter came to about $1.3 billion, compared with almost $1.4 billion in the same period a year earlier. For the full year, operating revenues were up about $45 million to $6 billion.
The St. Louis-based utility said earnings fell in the quarter because of mild winter temperatures, which lowered retail electric and natural gas sales. The earnings drop was partially offset by the company’s large investments in electric transmission and delivery, Ameren said. Earnings were also helped by the 18-month staggering of nuclear refueling and maintenance outages at the Callaway Energy Center, which kept the center running through 2015, the company said.
“We delivered strong earnings growth in 2015,” Ameren CEO Warner Baxter said in a statement. “Despite some challenges, including very mild fourth-quarter weather, we were able to achieve this growth through the continued execution of our strategy, which includes allocating capital to jurisdictions with modern, constructive regulatory frameworks and managing costs in a disciplined manner.”
In 2016, Baxter said, the company would work with key stakeholders to “modernize Missouri’s regulatory framework to better support investment in that state’s aging energy infrastructure for the long-term benefit of our customers and the state of Missouri.”
Ameren offered a less sunny outlook for 2016 diluted earnings per share, projecting between $2.40 and $2.60, and the company cautioned that decreased sales to Noranda Aluminum, Ameren Missouri’s largest customer, could cut shares by 13 cents this year. Ameren is currently working with lawmakers to save the Southeast Missouri smelter from closure while it seeks near-automatic rate increases for itself. Looking beyond the year, however, Ameren expects diluted earnings per share to grow 5 to 8% annually to 2020. Earlier in February, Ameren’s board of directors declared a quarterly cash dividend of about $0.43/share.
Public Service Enterprise Group (PSEG) on Friday reported that fourth-quarter earnings dropped to $309 million ($0.60/share) from $476 million ($0.94/share) for the same period in 2014, as the company dealt with unseasonably mild weather.
Operating earnings for the period — which exclude one-time costs — rose to $255 million ($0.50/share), from $247 million ($0.49/share) the previous year.
Earnings for all of 2015 were $1.7 billion ($3.30/share), up from $1.5 billion ($2.99/share) a year earlier.
Operating earnings for the year were $1.5 billion ($2.91/share), compared with $1.4 billion ($2.76/share) in 2014.
“Our results reflect the benefits of excellent performance and robust organic growth, which offset the impact of low energy prices on earnings,” CEO Ralph Izzo said on a call with analysts.
Izzo noted that in 2015, Public Service Electric & Gas invested about $2.7 billion in enhancing the system’s resiliency and its reliability. It placed into service key transmission upgrades, including the Susquehanna-Roseland line and the Mickleton-Gloucester-Camden line.
Meanwhile, PSEG Power plans to invest $2 billion over the next three to four years to add an estimated 1,800 MW of combined cycle, gas-fired turbine capacity, he said.
“And, after clearing the most recent capacity auction in New England, Power will construct a new 485-MW combined cycle unit at its existing Bridgeport Harbor station site, giving us an enviable and growing position in both energy and capacity markets in Southwestern Connecticut,” Izzo said.
PJM’s first 2016 proposal window for reliability projects opened Feb. 16 and will close March 17.
A PJM study found Dominion’s Carson–Rogers Rd. 500-kV line will be overloaded if the Carson–Rawlings 500-kV circuit is lost.
The RTO is looking to address problems on Dominion Resources’ Carson-Rogers Rd 500-kV and Chesterfield-Messer Rd-Charles City Rd 230-kV lines and the replacement of facilities meeting the transmission owner’s local criteria for end-of-life facilities.
The violations, which were identified in the 2020 generator deliverability and common mode outage analyses, were presented at the February meeting of the Transmission Expansion Advisory Committee.
The documentation necessary to participate is password-protected. Instructions on how to register for the proposal window are posted on PJM’s website. Also posted are the problem statement and requirements.
This is the first window for which a new proposal fee will apply for upgrades and greenfield projects. There is no fee for proposed projects below $20 million. A $5,000 fee will be assessed for projects up to $100 million. Proposals with a projected cost of more than $100 million must be accompanied by a $30,000 fee.
MISO’s Transmission Planning Business Practice Manual 020, which controls the expedited review process and replaces the current out-of-cycle reviews, is nearly complete, Matthew Tackett, a MISO principal adviser, told the Planning Subcommittee last week.
“In October, we approached the PSC with changes, and they were significant, with a complete rewrite of the bottom-up planning,” Tackett said during a presentation. The process change would take into account both near-term reliability planning implications, which MISO refers to as “bottom-up” planning, and long-term economic planning implications, which MISO calls “top-down” planning.
Tackett said the new BPM 020 language eliminates the cost allocation of baseline reliability projects under FERC Order 1000. His update to the subcommittee followed stakeholders’ comments on a second draft of the manual, which was circulated in December.
Entergy’s out-of-cycle request to spend $187 million on transmission to serve additional load in the Lake Charles, La. industrial zone sparked outrage among transmission developers and independent power producers. (Source: MISO)
“We agreed that since the changes were fairly widespread, stakeholders should comment. We think we’ve got the draft BPM down pretty well … and we’ve got pretty good consensus,” Tackett said. (See “MISO Adds Conditions for Stakeholder Notification and Advice into Expedited Review Process,” MISO Planning Advisory Committee Briefs.)
MISO made minor editorial fixes and accepted one request from stakeholders while declining a pair of others. The RTO agreed to the Transmission Owner sector’s proposal to include a reference in the BPM to TOs’ local transmission planning criteria.
But MISO rejected a suggestion that it remove the “redundant” practice of planning for maintenance outages and a NERC category P1 contingency (controlled interruption of electric supply to local network customers connected to or supplied by the faulted element). The RTO said it “continues to believe it is important to plan for maintenance outages in off-peak planning cases to ensure the system is designed with sufficient flexibility and robustness to provide options to outage coordination for allowing for planned maintenance.”
“It’s important that we plan the system with enough flexibility so we don’t tie [transmission owners’] hands,” Tackett said. “The bottom line is we need to make sure the system is planned to incorporate maintenance, but we also need to plan for contingencies.”
MISO also declined a suggestion that it specify a default measure to determine when a generator pulls out of synchronism. The RTO said that it would leave stability criteria up to individual TOs. “We don’t think we need that as default criteria because individual transmission owners have their own criteria, and we’ll respect that,” Tackett said.
MISO will present the final version of the language to the Planning Advisory Committee in March and ask for written feedback. Tackett said the goal is to incorporate all of the proposed changes by late spring during the annual review of BPM 020. MISO’s Senior Manager of Transmission Expansion Planning Thompson Adu said the RTO is targeting a May 8 deadline for completing revisions to all BPMs currently under review.
MISO: More Time Needed to Refine Non-Transmission Alternatives Process
MISO planners will take another month to work on a rewrite of their non-transmission alternatives process.
“There are lots of different issues we need to work through, and those would really impact MISO’s internal work processes. There were lots of good issues raised, and we need a bit more time with this,” Tackett said. The RTO would also have to incorporate NERC standards for transmission planning compliance, he said.
MISO is considering the use of an optimization tool to evaluate non-transmission alternatives and using modeling to determine if a non-transmission option is viable for an identified transmission need. Tackett said he preferred an approach that puts reliability first.
Tackett said there was sufficient time to go over the non-transmission process because it would be implemented in a subsequent planning cycle, most likely the 2017 Transmission Expansion Plan.
“When you think you have a lot of time, the clock tends to start ticking very fast, so we want to keep moving on this, but do our due diligence,” Tackett said.
He said his goal was to return with a presentation at the April Planning Subcommittee meeting. In the meantime, he asked for more stakeholder comments by March 15.
MISO to Bring Minimum Design Requirements Task Team Out of Retirement
MISO will reconvene its Minimum Design Requirements Task Team in March to modify standards for competitive transmission projects under BPM 029. Tackett said the RTO will extend the task team through the end of next year. According to MISO, the task team may introduce a second version of the BPM in time for the next planning cycle. MISO completed the latest round of revisions to BPM 029 last month.
FERC issued a Notice of Inquiry last week, seeking comment on potential changes to its rules on the provision and compensation of primary frequency response (RM16-6).
“In recent years, the nation’s electric supply portfolio has transformed to a point where fewer resources may now be providing primary frequency response than when the commission considered this issue in other relevant proceedings,” Jomo Richardson, of the Office of Electric Reliability, said in a presentation at the commission’s open meeting.
Primary frequency response is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. It, along with slower-responding secondary frequency response and system inertia — the release or absorption of kinetic energy by the rotating masses of online generation and load within — are crucial to reliability.
FERC is concerned that the growing integration of wind and solar resources, and the retirement of coal generators and other synchronous units, “have the potential to reduce system inertia,” making the system more susceptible to frequency changes in response to the loss of generation and reduction of load.
The NOI asks whether the pro forma interconnection agreements should be revised to require that all new generation resources have frequency response capabilities.
It also asks whether the commission should implement frequency response requirements for existing generators, and whether it should establish procurement and compensation mechanisms for the service.
“In my view, the questions posed are thoughtful and set a framework to explore a broad range of possible solutions,” Chairman Norman Bay said.
FERC has previously approved frequency response obligations for balancing authorities and permitted the sale of the service at market-based rates by generators. (See FERC to OK 3rd Party Sales of Frequency Response.)
WASHINGTON — FERC Chairman Norman Bay said last week he is reserving judgment on whether the Public Utility Regulatory Policies Act needs another overhaul until after an upcoming technical conference.
Speaking at the National Association of Regulatory Utility Commissioners winter meetings, Bay said FERC staff is planning the agenda for the June 29 technical conference (AD16-16), called in response to a request by congressional Republicans.
FERC ruled last month that Entergy did not have to purchase power from Occidental Chemical’s Taft plant in Louisiana because the PURPA generator had unconstrained transmission access and could sell its output in the MISO wholesale market. (Source: Occidental Chemical)
The 2005 Energy Policy Act amended the 1978 law, saying that utilities would no longer be required to purchase power from PURPA generators larger than 20 MW, which are shown to have nondiscriminatory access to wholesale markets. (See FERC: Entergy not Required to Buy from Large QFs.)
U.S. Sen. Lisa Murkowski (R-Alaska), chairman of the Senate Committee on Energy and Natural Resources, and U.S. Reps. Fred Upton (R-Mich.) and Ed Whitfield (R-Ky.), leaders of the House Energy and Commerce Committee, sent a letter to FERC in November asking for a technical conference to “identify any potential administrative or legislative reforms that may be necessary.”
The Republicans noted significant changes since the 2005 amendments, including the falling price of natural gas and renewable energy. Their letter cited congressional testimony from Berkshire Hathaway Energy complaining that it was required to sign a PURPA contract at rates that are 43% above market prices, costing customers an extra $1.1 billion over 10 years.
NARUC President Travis Kavulla asked Bay at a general session meeting whether any of the regulations implementing PURPA “stand out … as hopelessly outdated.”
“I don’t want to prejudge what we might learn at the tech conference,” Bay responded.
Bay added that there are limits to what the commission can do regarding the law. “It’s not like FERC can change anything that Congress has said,” he said.
Democrats, led by Sen. Maria Cantwell (D-Wash.), ranking member of the Senate energy committee, responded to FERC’s notice of the technical conference with their own letter Feb. 11, saying that the act “remains a singular federal backstop to support renewable energy in parts of the country that may otherwise have significant barriers.”
“In the past year, legislators and electricity regulators across the country have rolled back or debated rolling back incentives for renewable energy including renewable portfolio standards, energy efficiency resource standards and net metering programs,” they wrote. “… Until Congress chooses to act again, it would be improper for FERC to narrow the scope of [the law] any further.”
FERC on Thursday greenlighted FirstEnergy’s plan to spin off the transmission assets of Jersey Central Power & Light, Metropolitan Edison and Pennsylvania Electric into a new subsidiary, rejecting motions for a stay by New Jersey and Pennsylvania regulators, who also must approve the deal.
New Jersey regulators could vote on the transaction as early as this week.
FirstEnergy said the stand-alone transmission company will have a better credit rating, enabling it to save money on grid-strengthening projects under its Energizing the Future program (EC15-157).
The company told the New Jersey Board of Public Utilities and the Pennsylvania Public Utility Commission it expects to save $135 million over the 30-year life of $1.5 billion in projects. It said total transmission spending over the next 10 years could reach $3 billion in the two states.
State regulators had asked FERC not to rule on the deal until after they had rendered their decisions, saying that doing so would impair the states’ proceedings. Both state boards took issue with the classification of the new transmission company as a public utility, raising “jurisdictional issues regarding the safety and reliability oversight of the transmission systems,” according to the FERC order.
FERC determined that the transaction would not adversely affect state or federal regulation, and said that it is not the commission’s policy to delay a decision because of parallel proceedings.
The commission also rejected LSP Transmission’s request that FERC prohibit the new company from claiming a right of first refusal in a broader area than the FirstEnergy operating companies could individually. FERC Order 1000, which opens up new projects to non-incumbent bidders, reserves to incumbents upgrades to existing facilities as well as “local” projects.
In Order No. 1000-A, LSP noted, the commission clarified that “a local transmission facility is one that is located within the geographical boundaries of a public utility transmission provider’s retail distribution service territory, if it has one, otherwise the area is defined by the public utility transmission provider’s footprint.”
In rejecting the request, FERC cited as precedent a 2014 order in which it ruled that “the combined retail distribution service territories of the Entergy operating companies together constitute a single footprint for purposes of defining local transmission facilities.”
In its comments, the Public Power Association of New Jersey recommended FERC accept FirstEnergy’s offer to maintain a hypothetical capital structure of 50% debt and 50% equity for at least two years in order to not adversely affect rates.
FERC agreed and noted that the transaction includes a hold-harmless component preventing MAIT from passing on transaction-related costs to customers.
WASHINGTON — FERC Chairman Norman Bay said he expects the Supreme Court to take a nuanced view of federal-state jurisdictional issues when it hears oral arguments Wednesday in a dispute involving state subsidies for generation developers.
Bay said he considered the case as one of the court’s “FERC trilogy,” following its April 2015 ruling in ONEOK v. Learjet and its Jan. 25 ruling upholding the commission’s jurisdiction over wholesale demand response (FERC v. Electric Power Supply Association).
In the ONEOK case, the court found that state antitrust suits aimed at pipelines’ price manipulation do not improperly interfere with federal jurisdiction under the Natural Gas Act.
“The court ended up saying these state antitrust actions don’t have a direct aim of trying to interfere with the natural gas markets,” Bay explained. “Rather, they’re directed at many, many different kinds of markets. And so they said state jurisdiction there was not preemptive.”
The court will consider lower court rulings throwing out contracts in which generation developers won state-issued subsidies to build plants in New Jersey and Maryland. Competitive Power Ventures and state regulators have argued that the subsidies are legal. The courts ruled that the subsidies violated FERC jurisdiction over the wholesale electric market.
The two cases, Hughes v. Talen Energy, et al. (14-614) and CPV Maryland v. Talen Energy Marketing, et al. (14-623) were consolidated.
Based on its rulings in ONEOK and EPSA, Bay said, “I would expect the court to look to see what the aim of the state law is as well as the impact on the wholesale market” in its ruling.
“I think this is a sensible way of looking at things because the relationship between the wholesale and the retail markets is not one in which the two markets are hermetically sealed from one another,” he said.
CPP Ruling may not Come Until 2018
NARUC General Counsel Brad Ramsay said a Supreme Court ruling on the merits of the Clean Power Plan is unlikely before late 2017 and might not come before 2018.
The court granted a stay, preventing EPA from enforcing the rule, on Feb. 9.
The case is scheduled for oral arguments June 2 before a three-judge D.C. Circuit Court of Appeals panel, with a decision likely about three months later, Ramsay said.
The losing party will have 45 days to request rehearing by the entire 11-judge circuit. A rehearing ruling would come three to four months later.
The earliest the Supreme Court will decide whether to hear the final D.C. Circuit ruling is the end of 2016, Ramsay said. “I think it’s far more likely [in] the first quarter of 2017. It could easily go three, four months beyond that.”
If the court schedules briefing and oral arguments in the first part of 2017, the court could rule on the merits before the end of its term in June 2017.
“I think it’s more likely … to see the decision in the second half of the year, maybe even into 2018,” he said.
The Feb. 13 death of Justice Antonin Scalia, who sided with the majority in granting the stay, could change the timeline, however.
If Scalia’s seat is not filled before the case reaches the court, the timeline could be shorter, wroteThe Washington Post’s Robert Barnes. “If the appeals court upholds the plan, would the four remaining conservatives feel it was worth accepting an appeal if it were clear that it would be impossible to get a fifth vote from one of the liberals?” he asked.
Ramsay said the court’s unusual decision to stay the rule absent a lower court ruling on the merits indicated that the court is likely to grant certiorari and that several of the judges have serious doubts about the legality of the rule.
The stay “doesn’t tell you what they’re going to do on the merits, but it’s the only hint we have,” he said.
NARUC’s Assistant General Counsel Jennifer Murphy gave an additional update following a conference call with EPA officials Tuesday.
Murphy said EPA officials acknowledged the September 2016 deadline for filing initial compliance plans “will slip although interestingly, Janet McCabe [acting assistant administrator for the Office of Air and Radiation] seemed to leave open that perhaps the compliance deadline of 2022 would not be slipping.”
AWEA: Wind Growth to Continue Regardless of CPP Fate
American Wind Energy Association officials said wind power will continue growing for the next five years under the extended production tax credit even if the Clean Power Plan is struck down.
The trade group cited a report by Bloomberg New Energy Finance finding that 8.6 GW of wind power was added in the U.S. in 2015, besting solar (7.3 GW) and natural gas (6 GW). About 9.4 GW of wind is under construction with another 4.9 GW in advanced stages of development.
“The pipeline’s busy. It’s full,” AWEA CEO Tom Kiernan said at a press conference at the NARUC meetings.
“The Clean Power Plan — I would say for the five-year PTC window — probably doesn’t [have an] effect,” said Chris Brown, president of turbine maker Vestas Americas and incoming AWEA board chair.
Without the PTC, Brown said, the loss of the CPP could have an impact on wind’s competitiveness, along with “many different drivers — whether it’s the price of gas, whether it’s the other alternative sources of energy. What would we assume in terms of how much more efficient we can get?
“Obviously it’s a better looking forecast with the CPP, but it’s not a bad forecast without it either.”
Although the levelized cost of wind energy has dropped by almost two-thirds over the past six years, Brown said there’s no reason the wind industry can’t continue to reduce costs by increasing tower heights and rotor sizes. He noted that onshore turbines are not yet as large as the 7-MW turbines used offshore.
“Our friends in the solar business aren’t stopping [their cost-reduction efforts], so I don’t think that’s going to allow us to sleep very easy at night.”
APPA, ISO-NE Spar on Capacity Markets
One of the livelier sessions at the winter meetings came Tuesday afternoon, when Sue Kelly, CEO of the American Public Power Association, sparred with ISO-NE CEO Gordon van Welie over mandatory capacity markets.
Kelly was on the offense, complaining that capacity markets originally intended to supplement other resource procurement strategies have become dominant in the eastern RTOs.
“We believe resource decisions are better made closer to the customer. And that means at the state level and, in our case, at the community level,” she said. She warned state regulators in attendance of an effort to include in the House energy bill a provision that would require other RTOs to adopt provisions similar to ISO-NE’s Pay-for-Performance and PJM’s Capacity Performance rules.
Under Capacity Performance, she said, “consumers are paying a lot more money for most of the same resources.” She said RTO officials must be precise in how they identify the attributes they are seeking to procure, using “a scalpel rather than a meat cleaver.”
Van Welie responded that ISO-NE’s Forward Capacity Auction 10 last month saw a drop in prices from FCA 9, the first year that incorporated Pay-for-Performance, which rewards generators that over-perform while punishing those that fail to deliver. “One doesn’t have to pay more for performance,” he said. “This illustrates that a competitive market is really powerful at producing cost efficiencies. I would argue that there’s a greater danger that long-term contracting will lock in obsolete technology.”
Kelly and van Welie found some common ground, however, when the discussion turned to the Clean Power Plan.
Kelly said, “Regardless of what you thought of the [capacity] markets up until now, the era we are now entering into, I think is fundamentally unsuited for the current capacity market construct.
“We’re going to be trying to balance a lot of policy factors, including fuel and resource diversity, the need for ramping capacity, environmental compliance, greenhouse gas emission reductions, minimizing the long-term cost to consumers, which we’ve always cared about, and coordination of the infrastructure we have in our industry, including transmission and generation with pipeline capacity and other subsidiary infrastructure in other industries that’s needed for us,” she said. “We feel like these markets do not support those goals and therefore need to be fundamentally re-looked at.”
Van Welie acknowledged a conflict between the policy objectives of ensuring reliability and moving to more renewable and low-carbon energy.
“The challenge facing all of us is how do we keep these two policy objectives in balance?” he said. “Markets are working for reliability but they are not designed to favor fuel diversity.”
Van Welie said the shifts are rendering the term “baseload” obsolete.
“The baseload of the past … was coal and nuclear. I think we’re moving very quickly into baseload being natural gas, nuclear, energy efficiency — which is off all the time — and in the future I think we’re going to see renewables being baseload. So to me, baseload is just whatever is most efficient at producing energy … certain technologies are going to have high capital costs and low operating costs and those are going to tend to be the baseload resources.”
WASHINGTON — The National Association of Regulatory Utility Commissioners ended its winter meetings Wednesday with NARUC President Travis Kavulla’s interview of broadcaster Ted Koppel, whose 2015 book “Lights Out” alleges the U.S. is unprepared for the threat of cyberattacks on the nation’s grid.
Critics have accused Koppel of sensationalizing the threat and omitting key facts. But one might not have known that from the gentle probing Koppel received from Kavulla.
The Montana regulator pressed Koppel on his contention that investor-owned utilities lack sufficient incentives to aggressively pursue cybersecurity. But he left unchallenged the author’s claim that the electric industry can block FERC from imposing reliability standards that receive less than a two-thirds NERC membership vote.
“It’s a unique situation where an industry, in effect, is granted the right to draw a line under any restrictive legislation that the federal government might want to impose upon it and say ‘Sorry, we don’t accept it,’” Koppel said. “You’re all aware of the fact that … if FERC proposes something to NERC, NERC takes a vote on it and unless there is a two-thirds majority of NERC members — of the 3,200 or so U.S. power companies — unless they have two-thirds majority vote in favor, it is not accepted. The federal government has no unilateral power to impose legislation on the power industry.”
NERC Responds
NERC CEO Gerry Cauley, who was in the audience, disputed Koppel’s statements in an interview afterward.
“He’s missing the part where FERC can direct us to do a standard,” Cauley said. “We have the physical security, upgrading the cybersecurity standard, the GMD standard [that were ordered by FERC]. So when they tell us to do a standard, it’s not optional. And we actually have a backstop in our procedures … which says if the industry fails to approve a standard by the majority vote that we’ve been directed to do, our board takes over and approves that standard.
“We would never let that fail. And it’s never failed at this point. … Our continued existence as the [Electric Reliability Organization] is dependent on being responsive.”
Cauley said allowing NERC members to vote on standards is “valuable because it shows their support, that it’s a practical standard, the costs being passed to the customer are reasonable and there’s not going to be any litigation around it once it’s done. … There’s a value-add for having a vote, but it’s not the end. There’s no veto power by industry.”
Koppel’s publisher, Crown, did not respond to requests for comment on the criticism. FERC declined to comment.
Kavulla: Precise Language Needed
In an interview Friday, Kavulla defended his questioning of Koppel and said he was aware of controversy over the book.
He said both Koppel and Cauley — who complained to the NARUC president after the session — need to be more precise in their language.
“I’m not defending Ted Koppel. It seems to me clear that when he said the federal government had no unilateral authority, I think technically that’s untrue,” Kavulla said. “But what Gerry Cauley has told you is inaccurate or at least slightly misleading. Mr. Cauley is defending an approach where industry works to write regulations that regulate itself under generic direction by FERC … and then you seem to have Ted Koppel arguing the opposite position: that this industry is too sensitive to leave it up to regulations written by industry and that the federal government should take a more proactive role. I don’t know which is right.”
Although FERC can order standards, “it doesn’t proscribe what the standard should include,” Kavulla continued.
“There is a so-called backstop in theory, but to be clear that has never actually happened. Gerry Cauley uses the present tense voice in saying ‘Our board takes over.’ The one thing Gerry Cauley isn’t telling you is that has never occurred.”
EEI Weighs In
One industry expert who was interviewed by Koppel for the book said the author seemed uninterested in any information that didn’t support his thesis.
“We’ve heard this trope before: It’s the fox guarding the henhouse,” Scott Aaronson, the Edison Electric Institute’s managing director for national security issues, said in an interview. “Every other piece of fact proves that’s not the case.”
Aaronson said the NERC standards drafting process follows American National Standards Institute rules. “It is an open process. Anyone can participate,” he said. “We think that the process works very, very well despite Mr. Koppel’s protestations.”
Aaronson said Koppel also ignores “the important partnership that has developed between the government and owners and operators of critical infrastructure,” including the Electricity Subsector Coordinating Council, which includes 30 CEOs of operating companies and trade groups that meet three times a year with senior federal government security officials.
“He came to this with a thesis,” said Aaronson, who acknowledged he had not read the entire book. “It was effectively that the government is inept, the industry is profit motivated and our only option is to buy canned goods.”
Cauley agreed that Koppel appeared to dismiss the industry’s preparations, particularly its plans for the grid’s recovery after an attack.
“It’s a very serious area of concern — cyberattacks can happen. Our systems are particularly well guarded, but you can never say it won’t happen,” Cauley said. “I think he’s just not as aware of the things that have been done in preparation. … There are playbooks that exist that talk about roles and responsibilities. We exercise them thoroughly. The Grid Ex III, the exercise we went through for two days [in November], was actually more severe than his scenarios and we learned a lot. We found out what we had, what we didn’t have. We iterate on that every two years to keep getting better.” (See Two-Day GridEx III Tests Vulnerability to Terrorist Attacks.)
“Whoever [Koppel] got to talk to, he needs to talk to some more people to get the whole story.”
In an earlier session, retired Gen. Keith Alexander, former director of the National Security Agency, said the federal government needs to increase its information sharing, and the speed at which it does so, to address cybersecurity threats. “The government [has to] share what it knows about these threats. My experience in dealing with industry is they knew about 25% of what the government did. That’s insufficient. We’ve got to address that.”
Marcus Sachs, NERC’s chief security officer and the head of the Electricity Information Sharing and Analysis Center, agreed. “The offense needs to inform the defense. There’s a lot of really good national capabilities that are locked up [inside the] classified world. But those techniques need to be known to the defenders.”
Kavulla said the issue of NERC’s voting rules shouldn’t distract from the broader policy debate: Is it better to have stakeholders write standards subject to federal oversight, or should regulators write the rules subject to stakeholder feedback?
“How different would the standards look,” he asked, “if they were not subject to a two-thirds vote?”
Entergy lost $176.6 million (-$0.99/share) in 2015, compared to $940.7 million in earnings in 2014. Much of the loss was driven by its wholesale electricity business, Entergy Wholesale Commodities (EWC), which experienced a 46% drop in operational earnings.
