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?”
Md. Enters Fray over Dominion’s Coal Ash Water Release Plan
Maryland Gov. Larry Hogan’s administration said it intends to appeal a permit approved by Virginia regulators that would allow Dominion Virginia Power to release 215 million gallons of treated coal ash water into Quantico Creek, which empties into the Potomac River.
Dominion wants to seal five coal ash residue ponds at the Possum Point plant, where ash has been stored since the plant last burned coal in 2003. A company spokesman said its disposal proposal meets stringent limits imposed by the Virginia’s Department of Environmental Quality.
But Hogan isn’t so sure. “The fact is, Virginia’s decision to dump millions of gallons of polluted wastewater into the Potomac River could adversely impact both human and aquatic life,” chief Hogan spokesman Matthew Clark said. “Ignoring the risk simply isn’t an option.”
Entergy Says Fuel-Cost Savings Will Offset 8% Rate Increase
Entergy Arkansas says a projected decrease in fuel costs would help offset the customer impact of a requested 8% base-rate increase before the Public Service Commission.
The utility met with the PSC last month to discuss a settlement rate proposal for a $133.6 million rate increase. If approved, a customer with a $100 monthly bill would see it increase to $108.30/month.
United Illuminating, Eversource Propose Integrating Renewables
The United Illuminating Co. and Eversource Energy have submitted proposals to the Department of Energy and Environmental Protection for pilot projects to better integrate renewable energy into the electric distribution system.
Both utilities propose to install battery storage systems to help integrate the growing number of distributed energy sources on the grid. Another proposal is an online mapping tool that would allow the utilities to view existing power generators and proposed projects at the substation and circuit levels. “It would indicate where our distribution network has capacity to support in a neighborhood or whether that area has more solar generation feeding into it than the system can really handle,” said Camilo Serna, vice president strategic planning and policy for Eversource.
DEEP has until January 2017 to report to the legislature about the proposals, which were mandated last year.
Madigan Accuses Utility Execs of Misleading Regulators
Madigan
In a filing with the Commerce Commission, Attorney General Lisa Madigan said the chief executives of Peoples Gas and previous parent Integrys Energy Group violated state law last year when they withheld information from regulators on the soaring costs of the utility’s program to replace 2,000 miles of aging gas mains in Chicago.
Madigan said former Peoples President John Kleczynski and former Integrys CEO Charles Schrock knew the program’s costs had nearly doubled, from $4.6 billion to $8 billion, when they testified last year before the ICC on the proposed acquisition of Integrys by Wisconsin Energy Corp. The commission, which approved the $5.7 billion merger, is now investigating whether it should impose fines on company executives for misrepresenting material facts.
Madigan’s office, in seeking more information from the ICC, said the merger could have been impacted by the disclosure and raised questions of whether finalizing the transaction “was the primary concern of Integrys executives given the tremendous financial incentives that were conditioned upon the completion of the merger.”
A local attorney and his wife are challenging a recent settlement between Duke Energy and several parties concerning the Edwardsport coal gasification project. The agreement with the state’s Office of Utility Consumer Counsel and industrial customers would limit rates and provide money for solar projects and low-income customers.
Michael Mullett, co-founder of an advocacy group that was granted intervenor status by the Utility Regulatory Commission, says the settlement doesn’t protect residential ratepayers. He said that ratepayers should not be asked to finance any of the project’s $145 million in start-up costs. The settlement allows the utility to recover about $80 million of startup costs from customers.
Legislators are proposing to boost funding for a popular solar credit from $5 million to $7.5 million in an effort to maintain momentum for the solar industry. State Sen. Joe Bolkcom, the bill’s sponsor, said the Solar Energy System Tax Credit has been “hugely important” in convincing homeowners and business owners to install solar panels.
“There’s been $90 million in private investment for $11 million in tax credits,” said Bolkcom, a Democrat from Iowa City. “It’s created jobs in almost every county. It’s made a huge difference here.”
The solar tax credit was launched in 2012 with a budget of $1.5 million and funding has since been twice increased. The credit works out to about 18% of the cost of a typical solar installation.
Senate Moves to Block State’s Clean Power Plan Study
Olson
The state Senate has advanced a bill that would block the Corporation Commission from spending any money to study how to comply with the federal Clean Power Plan until a pending legal challenge is resolved.
Sen. Rob Olson (R-Olathe) added the amendment onto a bill that calls for disbanding the Kansas Electric Transmission Authority, an agency that was established to coordinate construction of new transmission lines to move wind energy to urban markets.
Lawmakers last year authorized the KCC and the Department of Health and Environment to develop a response to the Clean Power Plan, but only after review by a legislative oversight committee. The KCC is searching for a consulting firm to work on the state’s study.
Utilities Square off over Tx Right of First Refusal Bill
A bill that would allow existing state transmission owners first crack at building new local power lines attracted a standing-room-only crowd of rival industry advocates to a hearing in the House of Representatives.
The legislation was prompted by FERC’s decision to eliminate the federal right of first refusal on new transmission facilities ranging from 100 to 200 kV. FERC Order 1000 allows states to maintain transmission owners’ rights of first refusal for projects on their existing networks.
Supporters said the bill would ensure a reliable electric grid. But skeptics, including Bill Riggins, senior vice president for Kansas Electric Power Cooperative, said it would concentrate the transmission market. “The bill would eliminate open competition for transmission ownership, thus allowing current transmission owners, and their chosen affiliates, to monopolize future transmission in Kansas,” he said.
An administrative law judge questioned whether state regulators should allow the $4.9 billion sale of Cleco Power to a consortium of Canadian and Australian investors, citing a provision that allows buyers to pocket about $30 million in taxes collected from the utility’s customers.
Chief Administrative Law Judge Valerie Seal Meiners said the deal may be good for Cleco shareholders but not for the utility’s 286,000 customers in the state. Meiners has been reviewing the deal behind closed doors for the past 18 months.
The Public Service Commission has scheduled a vote Wednesday to decide whether the sale goes through. Cleco shareholders would sell their stock at a 15% premium, about $55.37/share, to a consortium of investors led by Macquarie Infrastructure and Real Assets, based in Sydney, Australia.
A legislative panel supports the idea of giving utilities the ability to reserve storage space in a proposed LNG facility, which would hold the equivalent of 1 billion cubic feet of gas for customers during peak winter heating months.
Northern LNG, which has proposed building the facility, has been pushing the bill, which the Legislature’s Energy, Utilities and Technology Committee is expected to endorse next week after working on final language.
One potential roadblock: The Legislature in 2013 gave utilities the authority to sign long-term supply contracts to finance an expansion of natural gas pipeline capacity. Lawmakers say pipeline expansion is a priority and they don’t want the LNG proposal to interfere.
Utilities in 2015 surpassed the state’s 10% renewable energy mandate, the Public Service Commission said in its sixth annual report, prompting conservationists to call for the state to set a higher target.
The PSC said all 75 power producers in the state met the target by Dec. 31. Under a 2008 energy law, they are required to maintain the same amount of renewable energy credits in the future.
Jack Schmitt, deputy director of the Michigan League of Conservation Voters, said the renewable energy standard now needs to expand beyond the 10% level. Schmitt said investment in renewable sources has leveled off at around $2.9 billion.
Ameren may be Forced to Install More Pollution Controls
EPA’s recent designation of St. Charles and Franklin counties as areas where sulfur dioxide levels are too high could force Ameren Missouri to install more pollution control equipment on its Labadie Plant on the Missouri River.
The state Department of Natural Resources also showed SO2 exceeding limits, but it recommended deferring action until the federal agency weighed in.
The SO2 levels have declined since Ameren switched to low-sulfur coal from the Western Powder River basin, but it has not been enough to comply with the law, according to EPA.
Six of the 10 bills in the state legislature that would have complicated Kinder Morgan’s controversial Northeast Energy Direct pipeline project are already dead, and the other four also seem imperiled.
Lawmakers are still considering a bill that would force pipeline operators like Kinder Morgan to pay reluctant landowners three times market value for any property taken under eminent domain. Another bill would require utilities using eminent domain to buy an entire property, not just the right of way.
Kinder Morgan’s Tennessee Gas Pipeline is pushing the $5 billion natural gas transmission project that would deliver Marcellus Shale gas to New England markets. The pipeline has aroused intense public opposition.
Voters will continue to choose members of the Public Regulation Commission.
The House Judiciary Committee voted Feb. 11 to table a proposed constitutional amendment to change the commission from an elected body to one appointed by the governor, effectively killing the bill. The 8-3 vote came after three of the five members of the commission spoke in opposition to the measure.
State Rep. Carl Trujillo said 40 states and U.S. territories have regulatory bodies whose commissioners are appointed and said he wanted to make sure that the commission’s decisions “are not changed by political winds.”
The state has joined the 17-state, bipartisan Governors’ Energy Accord Coalition, which develops energy policies and initiatives that expand clean energy sources, modernize energy infrastructure and build a clean energy economy.
“From the creation of a $5 billion Clean Energy Fund to implementing our ambitious Clean Energy Standard, New York is fully committed to our role as a national leader in growing the clean tech economy,” said Gov. Andrew Cuomo.
The governors of California, Connecticut, Delaware, Hawaii, Iowa, Massachusetts, Michigan, Minnesota, Nevada, New Hampshire, Oregon, Pennsylvania, Rhode Island, Vermont, Virginia and Washington have also joined the effort.
The staff of the Utilities Commission appears poised to recommend approval of Duke Energy Progress’ plan to replace a coal-fired plant at Lake Julian in Asheville with two natural gas units.
But staff said the company’s request for permission to build a third contingency plant if needed by 2024 was unwarranted.
If the project is rejected, the deadline for Duke to clean up coal ash at Lake Julian generation complex will be advanced.
Dynegy Presses Opposition to FirstEnergy, AEP PPAs
Opponents of the proposed power purchase agreements that would give FirstEnergy and American Electric Power guaranteed rates in the state are ratcheting up the rhetoric.
“The middle class is getting screwed,” Dynegy CEO Robert Flexon said at an energy forum in the state. “And quite honestly, folks, that’s how I feel about these PPAs. These only exist for Wall Street.” The Alliance for Energy Choice says nearly 55,000 emails protesting the proposed PPAs have been sent to elected officials and the Public Utilities Commission.
The agreements would guarantee the companies eight-year returns on power generated by some of the plants in their fleets. The companies have argued the PPAs are necessary to keep the plants operating in the competitive market.
Will Cap on Net Metering Stifle Alternative Energy Growth?
Solar energy advocates worry that a recent decision by the Public Utility Commission to limit the amount of energy residents can sell back to utilities might curtail alternative energy growth.
Under the ruling, residents who install new rooftop solar panels would be limited to 200% of a building’s historical usage or 50 kW.
Utilities had asked for even stricter caps, saying that the expense of paying residential providers the retail cost of their power was being passed down to consumers.
SPS Asks for $71.9M Increase to Cover Infrastructure Costs
Southwestern Public Service has filed for a $71.9 million rate increase for its Texas customers, just two months after the Public Utilities Commission of Texas denied the utility’s $42 million rate request and actually ordered a $4 million cut in revenue.
SPS said the increase in base rates is necessary because a significant amount of investment was not included in them, which are based on costs from a historical test period. The new request would increase a typical 1,000-kWh residential bill by $9.56/month, or 9.2%.
The PUCT in December answered the utility’s rate-increase request with a $4 million cut in revenue, but reallocated revenue among various customer classes so that the rate for residential customers actually went up $1.11/month on Feb. 1. SPS, however, says that reductions for fuel and purchased power costs over the past year have reduced a typical residential bill by more than $9/month.
Assembly Moves to Take Control of Clean Power Plan Compliance
The State Assembly is advancing bills that would require its approval of any proposal to comply with EPA’s Clean Power Plan, which has been stayed by the U.S. Supreme Court.
The bills were approved last week by House and Senate panels in the Republican-controlled legislature. Republicans contend that the federal mandates will raise energy costs and hurt businesses.
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.
Maryland Gov. Larry Hogan’s administration said it intends to appeal a permit approved by Virginia regulators that would allow Dominion Virginia Power to release 215 million gallons of treated coal ash water into Quantico Creek, which empties into the Potomac River.
Entergy Arkansas says a projected decrease in fuel costs would help offset the customer impact of a requested 8% base-rate increase before the Public Service Commission.
The United Illuminating Co. and Eversource Energy have submitted proposals to the Department of Energy and Environmental Protection for pilot projects to better integrate renewable energy into the electric distribution system.
A local attorney and his wife are challenging a recent settlement between Duke Energy and several parties concerning the Edwardsport coal gasification project. The agreement with the state’s Office of Utility Consumer Counsel and industrial customers would limit rates and provide money for solar projects and low-income customers.
An administrative law judge questioned whether state regulators should allow the $4.9 billion sale of Cleco Power to a consortium of Canadian and Australian investors, citing a provision that allows buyers to pocket about $30 million in taxes collected from the utility’s customers.
A legislative panel supports the idea of giving utilities the ability to reserve storage space in a proposed LNG facility, which would hold the equivalent of 1 billion cubic feet of gas for customers during peak winter heating months.
EPA’s recent designation of St. Charles and Franklin counties as areas where sulfur dioxide levels are too high could force Ameren Missouri to install more pollution control equipment on its Labadie Plant on the Missouri River.
Six of the 10 bills in the state legislature that would have complicated Kinder Morgan’s controversial Northeast Energy Direct pipeline project are already dead, and the other four also seem imperiled.
The staff of the Utilities Commission appears poised to recommend approval of Duke Energy Progress’ plan to replace a coal-fired plant at Lake Julian in Asheville with two natural gas units.