The Gulf Coast Power Association (GCPA) held its MISO South Regional Conference in New Orleans Feb. 18. Here’s a sampling of what we heard:
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FirstEnergy Q4 Earnings down
By Suzanne Herel
FirstEnergy last week reported fourth-quarter operating earnings of $0.58/share, compared with $0.80/share for the same period in 2014, citing greater planned operating expenses, higher tax rates and lower distribution deliveries.
Those factors were tempered by increased transmission revenue, a greater commodity margin for its competitive business and resolved rate cases in West Virginia, New Jersey and Pennsylvania, the company said.
“This year, we will continue to focus on regulated growth through our Energizing the Future transmission initiative, while strengthening our utilities business and managing risk across the company,” CEO Charles Jones said. “We also look forward to resolving our Ohio Electric Security Plan, which will shape our longer-term strategic outlook.”
On a non-adjusted basis, the Akron, Ohio, company reported a net loss for the quarter of $226 million ($0.53/share) on revenue of $3.5 billion, compared with a net loss of $306 million ($0.73/share) on equal revenue for the same quarter in 2014.
Operating earnings for the full year were $2.71/share, compared with $2.56/share for 2014.
Jones provided first-quarter 2016 guidance of 75 to 85 cents/share. He said in a call with analysts that he would not provide guidance for the full year until the Public Utilities Commission of Ohio rules on a proposed power purchase agreement proposal designed to shore up FirstEnergy’s Davis-Besse Nuclear Power Station and the Sammis Plant. He expects a decision in March. (See Next up in Ohio PPA Battle: Dynegy Weighs in.)
Peppered with questions from analysts regarding the potential effects on the company if PUCO denies the agreement, Jones and Chief Legal Officer Leila Vespoli said they were optimistic and declined to prognosticate.
“What I’ve said is we will deal with that outcome when we have it, and we will communicate at that time what our earnings guidance for 2016 is, what our future growth plans for the utilities are, what our future equity needs might be, if anything, to support that growth.” Jones said. “I’ve consistently said I think that generation, transmission and distribution are all critical assets in terms of serving customers, and right now I don’t see any strategic change there for us.”
Opponent of the plan have asked FERC to weigh in, and Vespoli said she expects the commission to do so before PJM’s Base Residual Auction in May.
FERC last week approved a separate initiative in which FirstEnergy plans to spin off the transmission assets of Jersey Central Power & Light, Metropolitan Edison and Pennsylvania Electric into a new subsidiary. (See FERC OKs FirstEnergy’s Tx Spin-off; N.J., Pa. Approval Still Needed.) The deal also needs the approval of regulators in Pennsylvania and New Jersey, which Jones said he expects by mid-year.
Entergy Reports 2015 Loss off of Nuke Closures
By Ted Caddell
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.
Warm Winter Drives Down Ameren Quarterly Earnings
By Amanda Durish Cook
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.
PSEG’s Q4 Earnings Wilt amid Mild Weather
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.
— Suzanne Herel
PJM Opens First Reliability Proposal Window of 2016
PJM’s first 2016 proposal window for reliability projects opened Feb. 16 and will close March 17.
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.
— Suzanne Herel
MISO Planning Subcommittee Briefs
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.
“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.
— Amanda Durish Cook
FERC Seeking Comments on Primary Frequency Response
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.)
— Michael Brooks
Bay: ‘Too Soon to Say’ if PURPA Needs More Changes
By Rich Heidorn Jr.
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.
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 OKs FirstEnergy’s Tx Spin-off; NJ, Pa. Approval Still Needed
By Suzanne Herel
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 to Spin off its Last Utility-Managed Tx Assets.)
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.