Dynegy told federal regulators last week they should reject complaints over its bidding in MISO’s capacity auction last April, saying the challenges suffer from a “fatal” procedural flaw.
In May, the Illinois Attorney General and Public Citizen filed complaints asking the Federal Energy Regulatory Commission to investigate Dynegy’s behavior in the Planning Resource Auction, which resulted in a nine-fold price increase for Zone 4 (EL15-70). Several other market participants, including Southwestern Electric Cooperative, also have filed protests over the results.
Dynegy, which has the commanding share of capacity in Zone 4, has previously denied there was any manipulation or underlying flaws in the MISO auction. (See Dynegy: No Evidence of Misconduct in Auction.)
In a July 30 filing, Dynegy said efforts by Illinois Attorney General Lisa Madigan to retroactively change the results of the auction “run squarely afoul” of previous FERC decisions.
Precedent Cited
The company cited a 2008 challenge by the Maryland Public Service Commission over PJM capacity auction results. The commission ruled that it would not invalidate results of completed capacity auctions that were conducted in accordance with approved market mitigation measures and were deemed by an independent market monitor to be competitive.
“So too here: because the complainants in these cases have not alleged that MISO violated its Tariff, and because [MISO Market Monitor David Patton] has confirmed that the results of the [auction] were competitive, the complainants’ challenges to those rules fail as a matter of policy,” Dynegy told FERC.
Dynegy said that although the attorney general wants the auction retroactively invalidated, “it never alleges, much less substantiates, any violation of the MISO Tariff.”
The company also said that Southwestern, which filed a complaint alleging that the auction results were unreasonable, also fails to show that MISO violated its Tariff.
“The complainants’ failure to clear that hurdle was fatal from the outset. Their more recent continued silence on the point only serves to underscore that failure,” Dynegy told FERC.
New York regulators last week began to sketch out the details of their ambitious Reforming the Energy Vision (REV) initiative with a white paper on rate design that seeks to upend business models that have been in place for more than a century and establish the state as a leader in the shift to distributed energy resources (DER).
The New York Public Service Commission staff straw proposal is intended to address the “discontinuity” between traditional cost-of-service regulation and the “multi-sided” market envisioned in Reforming the Energy Vision, with customers that are also producers and utilities that also serve as “platforms” for vendors offering services that help consumers reduce or time-shift their energy use.
That means utilities will see less of their earnings from centralized generation and returns on capital investments and more on service revenue and incentives tied to energy reductions, reducing transaction costs and increasing the volumes of DER, such as rooftop solar, microgrids and storage.
“The ratemaking paradigm must create alternatives to the current financial and institutional incentives and provide opportunities for utilities to earn from activities that achieve their service obligations in a manner that supports reductions in the total customer bill,” the paper says.
“The intent of REV is to harness markets to achieve innovative and cost-effective solutions, with utilities facilitating those markets both in their system planning and in day-to-day operations. Financial incentives and economic signals must be in alignment with this goal.”
In February, the PSC issued its “Track 1” order that created a framework for the shift from centralized generation to a customer-centric market that encourages adoption of clean distributed energy resources. The commission said that business as usual is no longer a viable option for utilities in meeting their statutory responsibilities to New Yorkers. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
Last week’s white paper will be the foundation for an anticipated “Track 2” order on ratemaking changes. “Track 2 looks closely at how we’re going to align the utility investment earning capacity with customer value,” Anthony Belsito, a policy advisor for the PSC, told the Infocast New York Reforming the Energy Vision Summit last week. (See related story, Public Helping Drive New York REV Agenda.)
Gradualism
The paper said that changes to rate design formulas must not cause large, sudden increases in customer bills. And this “gradualism” should also apply to industries such as solar and energy efficiency providers, it said. “Any changes affecting these industries should provide ample time for businesses to adapt and plan for new forms of opportunity.
“For the same reason, rate design changes should be oriented toward investments going forward, versus investments already made. To the extent possible, customer investments already made under assumptions of a program such as [net energy metering (NEM)] should not be disrupted.”
The report says concerns about the impact of NEM on utility earnings are “inconsequential” at current penetration levels.
“Input from the DER industry makes clear that the simplicity and predictability of NEM is very important in engaging customers and providing certainty to investors. Staff does not believe that there is any value in changing NEM for mass-market customers with on-site [distributed generation] at this time.”
Granularity vs. Simplicity
One of the challenges observed by the PSC is the conflict between increasing granularity in cost allocation and maintaining simplicity in billing, particularly for residential customers. That, the staff said, is where aggregators can play an important role. “Customers themselves may not need to see complex rates if a service provider or aggregator sees and manages complexity for them,” it said.
LMP+D
The paper proposes a new method for calculating the value of DER: adding a distribution component (“D”) to the wholesale LMP pricing (location-based marginal price of energy, as New York refers to it).
“The current convention of crediting at the average retail rate may be either too little or too much based on the nature of the resource and its location,” the paper says.
Click to zoom.
The value of D can include load reduction, frequency regulation, reactive power, line-loss avoidance and resilience.
The PSC plans to develop ways to calculate LMP+D in proceedings involving utilities and DER providers. Staff called for the state’s utilities to adopt software to determine distribution-level marginal costs.
LMP+D can incent net-metered facilities to install smart inverters that can increase the amount of solar generation that can safely be interconnected to a circuit. Staff said the commission should consider requiring smart inverters on future net-metered projects.
While the valuation of DER should vary by location, the paper says, customer charges should remain indifferent to location.
Customers participating in a utility demand response program or exporting power to the grid should receive compensation based on LMP+D, staff said.
Customers who supply only a portion of their electricity and do not participate in a utility program would receive no significant credits from their utilities. “In this circumstance, even when the ‘value of D’ as a service to the grid can be calculated, the reduction of the customer’s bill should continue to be based on the average cost of service. That is, NEM as it is currently constructed should remain applicable.”
Reforming the Energy Vision Rate Design
The paper proposes several additional changes:
Demand Charges — The paper proposes “for comment and further development” the concept of replacing part of the kilowatt-hour and fixed customer charges with a peak-coincident demand charge. “Because long-run distribution marginal costs are driven by coincident peak on a circuit-by-circuit basis, customers’ usage at system peak provides the most accurate measure of system costs. And, unlike fixed customer charges, peak demand can be managed by customers via DR, energy efficiency and/or DG,” staff said. Fixed customer charges should reflect only the costs of distribution that do not vary with customer demand.
“This change is not proposed as a mere reallocation of costs among customers,” the paper said. “It is proposed as part of a broader strategy to reduce long-term system infrastructure needs, encourage the optimal development of DER, discourage uneconomic bypass of the distribution system and maintain affordable rates for all customers.”
Time-of-Use Rates — The paper says utilities should develop time-of-use rate demonstration projects and offer technologies that have been shown to increase peak reduction savings, such as in-home displays, “energy orbs” and programmable and communicating thermostats. The paper cites studies showing TOU rates resulting in peak reductions as high as 47%. “Peak load reduction impacts are seen to increase as the peak to off-peak price ratio in TOU rates increases,” it added.
Smart Home Rate — The PSC said early-adopter consumers should be able to opt in to new rate structures. “A gradual approach to changes in mass-market rates should not prevent customers who are willing and able to begin participating in energy markets as active consumers from doing so.”
C&I Rate Design — While rates for commercial and industrial customers are more advanced than for mass-market customers, the report calls for additional improvements, saying demand rates should be more precise and reflect the time of energy use. “Current non-coincident demand rates can have the effect of inhibiting a customer from shifting load to off-peak times,” it says. “For example, a customer investing in storage to purchase off-peak power and utilize it at peak times might face an increased demand charge due to the shift in usage to the off-peak time.”
It called for utilities to examine their C/I rates and propose improvements in their next rate filing.
Standby Service Tariffs — Standby rates, which apply to large customers that generate much of their power on-site and use the distribution grid as a backup, can be another barrier to DER. The PSC recently expanded an exemption from standby rates for four years while it studies rate design changes. Standby rates are related to net metering and to the general rate design issue of fixed versus variable rates, the report notes. “In each case, the responsibility of a customer for the cost of the customer’s reliance on the distribution grid is at issue,” the staff said. “The cost of remaining connected to the grid should generally be lower than the cost of building redundancy and independence into a self-generation system.”
KANSAS CITY — SPP General Counsel Paul Suskie briefed the Regional State Committee last week on several seams and interregional issues. At times, however, he could say little.
Stressing the confidentiality of settlement negotiations with MISO over its use of a 1,000-MW contract path between its North and South regions, Suskie said, “I can say all parties are extremely close to a settlement. Hopefully, that will be resolved in the near future.”
Suskie said settlement negotiations also are ongoing with five seams neighbors who were among those intervening or filing protests with the Federal Energy Regulatory Commission regarding Tariff and bylaw changes to accommodate the Integrated System: Missouri River Energy Services, Montana Dakota Utilities, Municipal Energy Agency of Nebraska, Montana Consumers Council and Otter Tail Power.
SaskPower assets (click to zoom).
Suskie said the issues are not a roadblock to the Integrated System’s incorporation. “If these negotiations aren’t resolved, they will simply be referred to hearing,” he said.
With the Integrated System’s full incorporation, SPP will create a northern seam in North Dakota. Suskie said the interconnection will be limited, consisting of a 230-kV line with Saskatchewan utility SaskPower. SaskPower will be SPP’s first international market participant.
Interregional Projects
Suskie also briefed the committee on SPP’s interregional projects with MISO. The projects, all recommended for approval by a joint SPP-MISO study, include construction of a 345-kV line between Nebraska and Kansas, a series reactor on a 115-kV line in northeast Louisiana, and the rebuild of a 138-kV line south from Shreveport to Wallace Lake.
The projects are now going through each RTO’s regional-review process; SPP completed its in time for the April board meeting. The largest, the 78-mile, 345-kV Elm Creek-NSUB construction project, has an estimated cost of $140.6 million. Because SPP will receive 80% of the project’s benefit, Suskie said, it will pick up 80% of the costs, which will be allocated under the RTO’s highway/byway allocation process. (See 3 MISO-SPP Transmission Projects Move Forward.)
Integrated Marketplace Performing Well
Bruce Rew, SPP’s vice president of operations, delivered a one-year update on the Integrated Marketplace, saying its system availability has exceeded expectations, with the real-time balancing market successfully solving 99.95% of all its five-minute intervals.
He said the market had been delayed from posting just twice — once in June 2014 due to a modeling issue and again in December when a software problem affected participants’ ability to submit offers.
SPP’s balancing authority has maintained compliance with North American Electric Reliability Corp. standards, Rew said, and capacity overage has been reduced from the previous energy imbalance service (EIS) market. The EIS market’s final two months, January and February 2014, averaged more than 6,000 MW of un-dispatched capacity. The Integrated Marketplace has exceed 3,500 MW just once.
The Integrated Marketplace went online with 103 market participants. There are now 148 participants, with 98 classified as financial-only and 50 as asset-owning. The EIS market, by contrast, had only 50 participants.
SPP is currently testing improvements to its market-clearing engine performance and day-ahead reliability unit commitment process.
Bylaws, Waiver Request
The RSC also accepted recommended changes to its bylaws, reviewed updates from the July Markets and Operations Policy Committee meeting and approved SPP’s recommendation to reject Kansas City Power and Light’s waiver request to revise a transformer’s voltage level for cost-allocation purposes.
Superior Court Directs Suit Against Delmarva to PSC
A class-action challenge to Delmarva Power and Light will be heard by the Public Service Commission after a Superior Court judge ruled that the court doesn’t have jurisdiction. William Whipple III filed the case against the state’s largest utility, arguing that its Bloom Energy Servers program consumes more natural gas than Delaware’s Coastal Zone Act allows. The result, Whipple said, is higher, rather than lower, bills for customers.
But Superior Court President Judge Jan Jurden said the issue comes under the state’s Qualified Fuel Cell Project tariff, which is overseen by the Public Service Commission. The Bloom Energy fuel cell program is partially subsidized by Delmarva customers.
“Plaintiff’s claim for ‘unjust or unreasonable rates’ is a challenge to the QFCP tariff, a regulatory policy which falls within the PSC’s exclusive jurisdiction,” she ruled.
New Calculator Helps Residents Shop for Cheaper Power
Residents have a new free calculator at their disposal to help them save money in the electric market.
The Citizens Utility Board created the CUB Power Deal Calculator to help residents learn what they would pay with an alternative electric supplier compared with their regulated utility, Commonwealth Edison or Ameren.
From 2010 to 2013, when ComEd was locked into higher-priced contracts, it was simpler for consumers to find better deals. Now, however, the last of those contracts has expired.
A June report by the Commerce Commission’s Office of Retail Market Development indicated that ComEd is likely the best deal in the current market. The ICC report found that over the last year, those who got their power from ComEd saved $73 million compared with customers who signed up with an alternative electric supplier.
The calculator can be used for individual plans or deals negotiated by communities.
Gov. Charlie Baker said last week that his administration is ready to introduce legislation that is expected to address caps on solar power net metering, a hot issue in the state these days. Baker and state officials offered few details of the proposed legislation, saying only that it would build “upon the success and continued growth of Massachusetts’ solar industry while ensuring a long-term, sustainable solar program that facilitates industry growth, minimizes ratepayer impact and achieves our goal of 1,600 MW by 2020.”
The promise of further legislation comes after the Senate approved a bill that raises the solar power net metering cap to 1,600 MW. But the bill was criticized by an industrial users group. Associated Industries of Massachusetts said it would provide a subsidy that “could add as much as $600 million to the electric bills of Massachusetts consumers, businesses and institutions.” The group said the bill benefits only those who are able to install solar facilities, at the expense of those who can’t.
PUC Approves $125 Million Upgrade to Crude Pipeline
The Public Utilities Commission approved a $125 million upgrade to a crude oil pipeline that serves two refineries in Minneapolis. Minnesota Pipe Line asked for approval to build six new pump stations and to upgrade others along the 305-mile pipeline. The upgrades will more than double the pipeline’s capacity to 350,000 barrels per day.
Minnesota Pipe Line is co-owned by Flint Hills Resources, owner of Rosemount’s Pine Bend refinery; Northern Tier Energy, which owns the St. Paul Park refinery; and a third investor. The pipeline is operated by Koch Pipeline — like Flint Hills Resources, a unit of Koch Industries.
Small Hole Found, Filled in Protective Wall at Hope Creek
Workers discovered a small hole in a protective wall at the Hope Creek nuclear plant last week, but the reactor — stored in a separate structure — was not compromised, according to PSEG Nuclear.
The 1-inch hole was noticed by workers about 2 p.m. Tuesday and was sealed within two hours. The opening was found inside a closed auxiliary building and did not open into the environment, the utility said. It said that the primary containment containing the reactor core and major safety systems were unaffected, and that operations were uninterrupted.
PSEG Nuclear spokesman Joe Delmar said the hole apparently dated to the original construction when concrete was formed and poured. “There are more than 100 of these holes. All of the other holes were filled with grout/filler material,” he said. “There is no evidence that there was grout/filler in this hole. We continue to investigate and determine if it may have been filled at one time and not refilled.”
A report just released by the North Carolina Sustainable Energy Association shows that geothermal energy is a growing industry in the state, generating $143 million in revenue in 2014 and accounting for about 3% of the state’s clean energy income. It says that since the North Carolina Renewable Energy Investment Tax Credit was extended to geothermal installations in 2009, more than 10,500 units have been shipped to the state.
The report also said that because of uncertainty surrounding the survival of the tax credit, geothermal installation growth stagnated in 2014. According to a survey conducted by the NCSEA, the tax credit was the single most important consideration among those who decided to install geothermal systems, with 92% of respondents saying it was a determining factor.
“Energy efficiency is the low cost, least risk resource and [geothermal heat pumps] are the most energy-efficient technology for satisfying the thermal loads of homes and buildings,” said Robert Rust, territory manager for WaterFurnace International.
A wind farm originally proposed by a California company whose ownership was transferred to a North Dakota firm is again up for consideration before the Public Service Commission. The Antelope Hills Wind Project, a $240 million, 172-MW wind facility, originally received a permit in December. Ownership transferred to SUNE North Dakota Holdings in April, and the company has to reapply for approval. A hearing is set for September to consider the project.
The wind farm would be constructed on 22,000 acres near Beulah. While the project still calls for 85 turbines, the location of some of the turbines has changed.
FirstEnergy and American Electric Power are challenging how much they must pay solar owners for excess power and how much of it they are required to buy back, now that there are nearly 1,600 solar arrays operating in the state.
The Public Utilities Commission is considering revising its January 2014 ruling limiting net metering to 120% of a user’s average monthly demand over the previous three years.
The two utilities also have taken their challenge to the state Supreme Court, but the court is waiting to rule until the commission reconsiders its position.
FirstEnergy CEO Wants State Power Industry Re-regulated
FirstEnergy CEO Chuck Jones would support state re-regulation of the electric utility industry “in a heartbeat,” he told ThePlain Dealer. That’s after FirstEnergy fought seven years ago to have the industry deregulated, with electricity rates set by wholesale markets without influence from the state.
“I think it makes sense. I am trying to save a company,” he said.
In 2008, FirstEnergy was poised to prosper from coal-fired plants that provided some of the cheapest power in the state. Now, Jones said, FirstEnergy may not survive if it can’t convince the Public Utilities Commission to force ratepayers to cover the full cost of electricity from two of its huge coal and nuclear plants.
Talen Reaches Proposed Settlement on Coal Ash Spill
Talen Energy, the company formed by the spinoff of PPL’s generation assets, has reached a tentative $1.3 million agreement with the Department of Environmental Protection that would cover damage caused by a 2005 coal ash spill at the Martins Creek Steam Electric Station. In August 2005, part of a retaining wall burst at a settling basin at the coal-fired plant, releasing about 100 million gallons of fly ash and water into fields and into the Oughoughton Creek and the Delaware River.
The settlement, which still needs to be approved by DEP after public comment, would result in Talen paying $1.3 million to settle all natural resource damage claims from the spill. PPL, then the owner of the plant, spent $37 million on the cleanup, including a $1.5 million civil settlement.
The coal units at the plant were retired in 2007. Talen Energy now operates three oil and natural gas units generating 1,700 MW at the site.
The first 440-ton steel foundation of the nation’s first offshore wind farm rising from the Atlantic Ocean was lowered from an enormous crane in about 100 feet of water off Block Island. The project that developer Deepwater Wind is building points the way toward a clean energy future for the country, U.S. Interior Secretary Sally Jewell said.
“A place like Block Island, which could only burn dirty diesel fuel, now will have the opportunity for clean, renewable energy,” Jewell said as she stood at the bow of a ferry as it rocked in the swells off the tiny island. She was accompanied to the site of the five-turbine wind farm, about three miles southeast of Block Island, by Gov. Gina Raimondo, the state’s congressional delegation, and other public officials.
Family Seeking Approval for Large-Scale Wind Project
A local family is gathering data with an eye toward developing a seven-turbine wind project on a ridge in Swanton.
The Belisle family is working with Vermont Environmental Research Associates to put together the plan before applying to the state for permission to build. The family has said it would like to begin construction by the end of 2016. When completed, according to Martha Staskus of Vermont Environmental Research, the 20-MW Swanton Wind farm would produce enough energy to power about 7,800 households.
In addition to gathering technical information for a feasibility study, the Belisle family is reaching out to neighbors and other community members to hear their concerns.
The project, however, is already facing some opposition. “The state has done absolutely nothing to recognize that this type of development causes tremendous harm to the environment and to the health and welfare of people living around the mountains,” said Annette Smith of the Danby-based group Vermonters for a Clean Environment. As a result of some complaints, a test tower is already being taken down.
A panel created by the Legislature to study the growth of solar power in the state will meet for the first time this week. The Solar Siting Task Force was charged with reviewing the design, location and regulation of solar electric generation facilities, and is due to report back to lawmakers in January with recommendations.
A new renewable energy law established the 10-member panel and set a requirement that 55% of the power sold by energy companies come from renewable sources by 2017 and 75% by 2032. The state has a broader goal of getting 90% of its energy from renewable sources by 2050.
The task force is made up of state and utility officials, a landscape professional and a member of the general public. It is responsible for addressing concerns raised by some municipalities and others about the fast growth of solar power projects in the state.
A recent study by the Acadia Center says the value of solar power to the grid — and to ratepayers connected to the grid — ranges from 19 to 23 cents/kWh, with additional societal values of 7 cents/kWh.
“Solar generation is a valuable local energy resource that provides significant benefits to ratepayers,” said Ellen Hawes, Acadia’s senior analyst for energy systems and carbon markets. The study said solar provides value to the electric grid by reducing energy demand, providing power during peak periods and avoiding generation and related emissions costs incurred by conventional power plants. The study suggests the overall grid value of solar is the sum total of those various benefits.
In addition to the value that solar provides to the grid, Acadia’s study found that it provides broader societal benefits, including environmental gains from reducing greenhouse gas emissions and other pollutants.
The Federal Energy Regulatory Commission last week denied a request to reinstate a generator interconnection agreement terminated by MISO last year after a wind developer failed to make milestone payments.
The commission denied Shetek Wind’s request to rehear an order it issued last October accepting MISO’s termination of the GIA (ER14-2681).
That agreement, which included transmission owner Northern States Power, provided up to 146.6 MW of interconnection service to Northern States’ Garvin, Minn., substation.
In October, FERC found that Shetek failed to meet milestone payments under the GIA and that extending the milestones without assurance that the developer would meet its obligations would present “harm to lower-queued interconnection customers in the form of uncertainty, cascading restudies and shifted costs necessitated if the project were to be removed from the queue at a later date.”
Northern States parent Xcel Energy said that since signing the agreement in 2007, Shetek had made no progress toward development.
Shetek’s plan was to install up to 60 turbines near Tracy, Minn. In 2006, the developer reported that it had raised $470,000 in equity from almost 40 landowner-investors in the project’s targeted area.
The company was seeking an extension of time to make progress payments and argued that Northern States breached its obligations to act in good faith.
Shetek said FERC’s decision last year was not in the public interest because termination would frustrate Minnesota’s interest in supporting community-based projects.
But FERC noted that both the state’s Public Utilities Commission and its Court of Appeals found that Xcel was not required to give special consideration to the project.
Ameren reported last week that earnings were flat in the second quarter, largely on milder temperatures that reduced demand for electricity.
The St. Louis-based company earned $150 million ($0.61/share) compared with $149 million ($0.61/share) in the same period last year. Operating revenues were $1.40 billion versus $1.42 billion last year.
Ameren said its results were buoyed by earnings from investment in electric transmission and delivery infrastructure, along with a lower tax rate.
The company raised its full-year earnings-per-share guidance slightly, to $2.48 to $2.68 from $2.45 to $2.65.
— Chris O’Malley
Lower Revenues Dim CMS Energy Profits in Q2
Second-quarter net income for CMS Energy fell 19% on a 8% decline in revenue, the company reported last week.
The Jackson, Mich.-based parent of Consumers Energy earned $67 million ($0.25/share) compared with $83 million ($0.30/share) during the second quarter of last year. Revenue was down to $1.35 billion, from $1.47 billion a year earlier.
Nevertheless, CMS reaffirmed its 2015 earnings-per-share guidance of $1.86 to $1.89, consistent with its goal of 5 to 7% annual adjusted EPS growth.
President and CEO John Russell said CMS is still on track to retire its seven oldest coal plants — amounting to one-third of its coal fleet — by next April. The units being shuttered are an average of 60 years old and will be replaced by gas-fired units.
Russell also said CMS will proceed with its first-ever utility-scale solar generating station. The 10-MW demonstration project will be evaluated for the potential of additional utility-scale units in Michigan.
— Chris O’Malley
Unfavorable Weather Cited in DTE Earnings Drop
DTE Energy’s second-quarter profits fell 12% on increased costs and unfavorable weather.
The Detroit-based company posted net income of $109 million ($0.61/share) compared with $124 million ($0.70/share) in the same quarter last year.
Operating earnings in DTE’s electric segment were down by $18 million, while the gas utility segment recorded a $3 million decline. Operating revenue for the company fell 15%, to $2.27 billion.
During a conference call, executives cited strong growth in the gas storage and pipeline business and in energy trading. As a result, DTE raised its 2015 operating EPS guidance to $4.54 to $4.90, from $4.48 to $4.72.
— Chris O’Malley
Eversource Q2 Earnings Jump 63%
Eversource Energy said last week that the company’s second-quarter profits this year increased by nearly 63%, from $127.4 million ($0.40/share) in 2014 to $207.5 million ($0.65/share).
“We had an excellent first half of 2015, with financial performance consistent with our targeted 6 to 8% long-term earnings growth rate and our 2015 projected earnings of $2.75 to $2.90 per share,” Eversource CEO Thomas May said in a statement.
“We don’t believe it poses any unanticipated challenges to the construction of the project,” said Lee Olivier, executive vice president of enterprise strategy and business development. He added that plans for site approval will be filed with state officials in “early to mid-fall,” with review taking about one year.
— William Opalka
Exelon: Quad Cities Decision as Soon as September; Awaiting Pepco Decision from DC
Exelon CEO Chris Crane told analysts during the company’s quarterly earnings conference call that if Illinois legislators fail to pass a law that would essentially guarantee profits for its nuclear plants, the company may be forced to close its Quad Cities generator, with a decision coming as soon as September.
Crane and other company officials have long said that three of its six nuclear stations in Illinois are losing money on the wholesale market, primarily because low natural gas prices are pushing wholesale power prices down.
Even anticipated revenue boosts from PJM’s Capacity Performance program “will not be enough to keep all the units economically viable,” Crane said. The decision on whether to keep its Clinton nuclear station open — which bids into MISO and therefore is governed by different rules — won’t be made until the first months of next year.
“We don’t take the decision lightly,” Crane said. “We understand the effect that we have on the communities and potential effect on employees, but this has been a long-term issue that we’ve been evaluating and trying to come to a resolution [on], and we’re staying within the timeline.”
Exelon reported second-quarter earnings of $508 million ($0.59/share) compared with $440 million ($0.51/share) this time last year.
The company said profit rose due to higher sales and a hedging-related gain. Crane also credited strong financial performance by Exelon Generation.
Crane also said the company is prepared to quickly finalize its $6.8 million acquisition of Pepco Holdings Inc., pending approval by regulators in D.C. As the company awaits the ruling, expected late this month, it extended the deal’s termination date from July 29 to Oct. 29.
Pepco’s second-quarter earnings were flat compared with the same period in 2014, with net income of $53 million ($0.21/share).
“Increased operation and maintenance costs, primarily driven by the implementation of a new customer information system, impacted second-quarter results,” CEO Joseph Rigby said.
— Suzanne Herel
FirstEnergy Beats Expectations
FirstEnergy beat its own expectations, reporting second-quarter net income of $187 million ($0.44/share) compared with $64 million ($0.16/share) for the same period last year, despite the fact that the company’s revenues stayed flat at $3.5 billion, the company said.
“We remain focused on implementing our regulated growth initiatives and our Cash Flow Improvement Project, which was launched in April,” CEO Charles Jones said in a statement. “I’m pleased that the opportunities we have identified as part of that project are expected to result in cash savings of $240 million by 2017, exceeding our original targets.”
Operating earnings for the Akron, Ohio, company’s regulated distribution business were flat compared with the same period last year, as the benefit of higher distribution revenues and approved rate cases was offset by higher operating expenses and a higher effective income tax rate.
The regulated transmission business saw higher transmission revenues, in part related to the company’s Energizing the Future plan to upgrade its grid.
The company’s competitive energy services benefited from lower operating expenses and a slightly higher commodity margin compared with last year.
The company said the loss reflected a $1 billion hit from discontinued operations of the competitive supply business.
For the same period last year, PPL had reported net income of $229 million ($0.34/share).
Not taking into consideration the spinoff and some other accounting items, the utility reported second-quarter earnings of $329 million ($0.49/share), an 11% increase from adjusted earnings of $296 million ($0.44/share) for the same period in 2014.
The company also narrowed its 2015 forecast range from ongoing operations to $2.15 to $2.25 per share and increased its quarterly common stock dividend to $0.3775/share.
“Based on the strong performance of PPL’s seven regulated utility businesses in both the U.S. and the U.K., the continued rate base growth from our significant infrastructure investment and our solid business plan to grow earnings per share, we are increasing the midpoint of our 2015 earnings forecast,” CEO William H. Spence said in a statement.
“The new PPL Corp. — with its strong growth profile, a solid dividend and diverse mix of holdings — is a unique and very compelling investment option in the U.S. utility sector,” he said.
— Suzanne Herel
PSEG Q2 Earnings Up 62%
Public Service Enterprise Group on Friday reported second-quarter net income of $345 million ($0.68/share) compared with $212 million ($0.42/share) for the same period in 2014.
“Our businesses performed well. [Public Service Electric & Gas’] expanded investment program is successfully translating into improvements in customer satisfaction at the same time operational improvements at PSEG Power supported increased output,” CEO Ralph Izzo said in a statement.
Operating earnings for PSE&G rose to $167 million ($0.33/share) from $151 million ($0.30/share) this time last year. The company attributed the boost to an expansion of its capital program, warmer-than-normal temperatures and a recovering economy.
Meanwhile, PSEG Power reported operating earnings of $110 million ($0.22/share) compared with $87 million ($0.17/share) this time last year.
The company said the results reflect improvement in operations of its nuclear and fossil fuel generating facilities, higher prices on its hedged energy output and a drop in the cost of its gas supply.
— Suzanne Herel
WEC Energy Group Erases $0.24/Share on Integrys costs
Costs related to its June acquisition of Integrys Energy put the squeeze on WEC Energy Group’s second-quarter profits.
Milwaukee-based WEC earned $80.9 million ($0.35/share), a 39% decline from $133 million ($1.04/share) in the second quarter of 2014. Excluding the acquisition costs, which cut EPS by $0.24, WEC would have reported EPS of $0.59.
Like many northern utilities, a cooler-than-normal June crimped electricity revenues. Operating revenues declined to $991.2 million from $1.04 billion last year.
WEC’s results do not yet include the financial performance of Integrys or its subsidiaries.
— Chris O’Malley
Xcel Reports Flat Earnings for Q2
Xcel Energy reported flat profits for the second-quarter, with earnings of $197 million ($0.39/share), compared with $195 million ($0.39/share) for the same period last year.
Minneapolis-based Xcel said the results were generally in line with expectations. Though the company missed analysts’ estimates by $0.01/share, it reaffirmed its full-year earnings-per-share guidance of $2 to $2.15.
Xcel blamed unfavorable weather conditions that affected customers’ heating and cooling costs and adjustments to a rate request in Minnesota.
Second-quarter electric margins increased due to new rates and riders in various jurisdictions and a lower Public Service Company of Colorado earnings test refund. Xcel said that increase was offset by higher depreciation, a lower allowance for construction funds and higher property taxes, operating and maintenance expenses and interest charges.
Xcel’s Monticello nuclear plant is operating at full capacity, having received final Nuclear Regulatory Commission approval. The facility was uprated to 671 MW from 600 MW in 2013, at a cost of $748 million (a $0.16/share hit to profits). Xcel said its Cherokee combined-cycle plant in Colorado completed its first-fire during the quarter and is on budget and on time.
PJM and nine interstate pipelines have signed an information-sharing agreement to improve the reliability and flexibility of natural gas supplies for the RTO’s generators.
The pipelines said they are willing to sign contracts to “firm up” services for generators that do not have primary firm service. The MOU notes that the pipelines may require additional facilities to provide firm service.
Each of the pipelines will provide PJM a description of services they are offering to generators that could satisfy the RTO’s Capacity Performance requirements. They also agreed to provide PJM a summary of services that have been requested by generators and the status of those requests. PJM may share any information obtained under the MOU with the Independent Market Monitor.
In return, PJM will provide the pipelines with performance requirements for gas-fired generators serving as capacity resources, including a demonstration of access to firm gas during the peak hours of the electric day and evidence of hourly flexibility — ensuring that generators will not seek compensation due to an inability to procure gas outside the normal scheduling window.
“This agreement sets the stage for greater coordination between electric generators and the natural gas pipeline industry,” said PJM Chief Operations Officer Mike Kormos in a statement. “As electricity-generating facilities increasingly turn to natural gas, it is important that we all communicate clearly to assure reliable service.”
“Continued dialogue will result in more informed decisions by the PJM market participants that operate and rely upon gas-fired electric generators,” said Don Santa, CEO of the Interstate Natural Gas Association of America.
According to data from the U.S. Department of Energy, natural gas surpassed coal as the country’s top source of electric power generation for the first time in April.
The pipelines signing the MOU are Dominion Cove Point LNG; Dominion Transmission; Columbia Gas Transmission; National Fuel Gas Supply; Natural Gas Pipeline Co. of America; Tennessee Gas Pipeline; Texas Eastern Transmission; Texas Gas Transmission; and Transcontinental Gas Pipe Line.
The agreement will run through June 2016, after which it will continue on a month-to-month basis unless terminated by the parties.
CARMEL, Ind. — News that MISO is reconsidering a market congestion project in Southern Indiana sparked renewed complaints from developers over the RTO’s transmission planning processes.
MISO officials told the Planning Advisory Committee on Wednesday that they were considering swapping one Southern Indiana project for a second one on which PJM has offered to assume more than one-third of the cost.
Despite a potential $29 million in savings for MISO, transmission developers accused the RTO of disregarding its transmission planning process and not giving stakeholders enough time for review.
The new development came as some stakeholders were still simmering over the way in which MISO approved Entergy’s $187 million out-of-cycle upgrade near Lake Charles, La. Only a few hours before MISO’s presentation to the committee, PAC participants were discussing ways to restructure the out-of-cycle review and approval process to address their concerns. (See Ideas to Reform MISO Out-of-Cycle Process Emerge.)
But it seemed that any goodwill created by potential out-of-cycle reforms had evaporated by the afternoon, when MISO proposed replacing the Southern Indiana project that was judged as having the highest benefit-cost ratio among proposed market congestion projects in the North-Central region: the 345-kV Duff-Coleman project, estimated to cost $67.2 million.
MISO planners are considering replacing the 345-kV Duff-Coleman transmission project (red dotted line) with the 345-kV Rockport-Coleman project (blue dotted line). The Rockport-Coleman project’s benefit-cost ratio to MISO jumps from 14.4 to 23.4 when PJM assumes the cost of the transformer. (Click to zoom.)
MISO staff said they are considering replacing Duff-Coleman with the project with the second-highest cost-benefit ratio, the $76 million 345-kV Rockport-Coleman line.
PJM recently proposed picking up the cost of a 765/345-kV transformer connecting the Rockport substation. “This would potentially reduce the total MISO cost by $29 million and make Rockport-Coleman 345-kV … the project with the highest B/C ratio,” according to the presentation.
Stakeholder Feedback Loop
George Dawe, vice president at Duke American Transmission Co., was incredulous.
“What you’re saying is that this needs to be done quickly. And we’ve already heard about the cost estimation process [this morning] and how there’s supposed to be a stakeholder feedback loop and [yet] there’s a whole bunch of things that tend to need to happen at the last minute [without stakeholder review or process], just before the System Planning Committee needs to get a recommendation. And we scurry around to try to find answers,” he said.
‘Rigidity of Process’
Jeff Webb, MISO’s director of planning, denied that the RTO was “flipping gears” or that it was suddenly committing to Rockport-Coleman. Webb said MISO is only exploring the idea because PJM came to the table with an idea that provided potential cost savings.
“The only thing we don’t want to happen is the rigidity of the process, George, to interfere with progress in doing the right thing. And I don’t think [the Federal Energy Regulatory Commission] would want that either, unless in doing so that we are somehow egregiously creating an inequity for someone.”
Dawe complained that, while he had seen a lot of cost information about the Duff-Coleman project, “I haven’t seen anything on Rockport.”
Digaunto Chatterjee, MISO senior manager of economic studies, countered that the RTO has been evaluating both Southern Indiana projects since at least the beginning of the year, and thus it is not comparable to an out-of-cycle project request. “This isn’t a brand-new project. We’ve been studying it.”
‘Smells Like’ Cross-Border
Dawe and other stakeholders questioned whether PJM’s financial assistance made Rockport-Coleman an interregional project subject to review by the Interregional Planning Stakeholder Advisory Committee (IPSAC).
“My issue is that it looks and smells like a cross-border project. And it’s not following that cross-border project process,” Dawe said.
Flora Flygt, strategic planning and policy advisor at American Transmission Co., echoed Dawes’ concern. “We’re now taking what is part of an [market efficiency project] process and now we’re turning it into [a multi-value project], an interregional MVP, basically.”
Chatterjee disagreed, saying it is not an interregional project as defined in the RTOs’ joint operating agreement.
“We’ve been through the IPSAC and it has resulted in no projects,” Webb added. “We’re looking for a way to get something to result in projects.”
During its annual meeting in June, MISO said it will reevaluate metrics used in evaluating market efficiency transmission projects (MEPs) because of concerns they are unduly conservative and prevent viable solutions to congestion. (See MISO to Reevaluate Metrics on Market Efficiency Tx Projects.)
Delays Feared
Chatterjee said MISO will soon discuss the matter further with PJM and make a recommendation — likely at the next PAC meeting.
Flygt said she feared the review could result in delays, with the next PAC not until Aug. 19 and the MISO Transmission Expansion Plan (MTEP) is scheduled to go to the board Dec. 10. “We’re sitting here at the end of July,” she said.
Webb insisted the review would not cause delays, and PJM’s Chuck Liebold assured the committee that his RTO could quickly analyze an interconnection request.
“The first thing I said [to PJM] was if this keeps us from taking an MEP to the MISO board in MTEP 15, it’s a show stopper,” Webb said. “If there’s a delay we’re doing Duff-to-Coleman, OK? If we can get this done and we can show ourselves and stakeholders that this is a better deal for MISO, we certainly want to let MISO know that.”
11th Hour Concerns
Flygt said that FERC Order 1000 requires transparency at every point in the process. “When you’re in a competitive market and you’ve got these processes to follow, I think it’s more important to follow the process than the implication that we’re getting here.”
PAC Chairman Bob McKee said he was concerned that, after all the analysis, the proposed alternative was only coming up now. “Why are we getting all this shuttle diplomacy and all of this right at the 11th hour, right before we’re to go to the board?”
Webb replied that PJM became aware of the potential for a win-win solution, albeit “late in the game.”
“I think it’s unfortunate that the awareness came late and I think that’s a process issue. That’s the point I’m raising,” McKee said.
No Violation of MISO Process
Kip Fox, director of transmission strategy and grid development at American Electric Power, said MISO identified three projects with similar benefit–cost ratios. “In my mind, this is the way the process is supposed to work. I don’t see a lot of process change. These projects have been talked about ever since we went through the [market congestion planning study] process.”
McKee wasn’t buying it. “I would say I respectfully disagree that this is how the process should work. The reason why I say this is that, look at all the confrontation that we’ve had,” he said.
Webb said if a plan is presented to MISO stakeholders that produces more benefits to the RTO at a lower cost, but the stakeholders rejected it because it didn’t follow a certain process that they were comfortable with, “I think we will want to make that clear so that FERC at the end of day can react to that too.”
If MISO stakeholders demonstrate that the project doesn’t follow the process and can’t be done, “then that’s probably the way it will end up,” he added.
Webb said that it was “a little murky” to him about what part of the process MISO is violating.
“We had the [Rockport-Coleman] project here already. The only thing new is that the entity that we already had studied, that we were going to connect to [PJM], said, ‘Yeah, that’s a great idea. … That’s the only change so I’m not sure that’s a big process change.”
KANSAS CITY — The Integrated Marketplace’s first 12 months of operations provided the highlights for SPP’s 2014 State of the Market report, which notes a maturing market, changing congestion patterns due to completed transmission projects and lower energy prices.
Alan McQueen, director of SPP’s Market Monitoring Unit (MMU), briefed the Board of Directors/Members Committee last week on the draft report.
The report says the market, which went live in March 2014, “provided wholesale electricity at modest prices that compare favorably to those in regions with well-established markets,” with LMPs generally tracking the steadily decreasing price of natural gas.
“We saw significant maturing and growth in the market, maturing in the market participants and in how they participated in the market,” McQueen said. He pointed to “robust participation” in the day-ahead market, with 99% of the reported load clearing, efficient management of wind resources and reductions in uplift.
“We saw fewer make-whole payments in this market, and that’s a good thing,” McQueen said. The report said make-whole payments made up less than 1% of electricity’s “all-inclusive price,” with 70% of make-whole payments related to reliability unit commitments.
Golden Spread Electric Cooperative’s Mike Wise, however, challenged McQueen’s assertion. He said the market’s make-whole payments are low because of its over-reliance on simple-cycle combustion turbines as quick-start resources in the RUC market.
“The market wants to use them all the time, but it’s not paying the startup costs,” Wise said. “We’re having more maintenance costs because they’re being run so much.”
In response, McQueen said the Monitor doesn’t believe startup charges should be included as costs recovered through make-whole payments.
“It’s an area of concern, but we have a difference of opinion,” McQueen said.
McQueen said the Market Working Group will study the issue further.
McQueen said there also needs to be further discussion with the MWG related to the transmission congestion rights (TCR) market. He said TCRs have been underfunded each month (85% of full funding), while the opposite is true of auction revenue rights positions (112% of full funding). “The concern is that if all the ARRs and TCR rights are allocated early in the process, they can’t be supported by the market later in the year.”
The report recommends reducing the amount of transmission capacity made available in the TCR and ARR process, earlier reporting of planned transmission outages and improvements to modelling of the conversion of ARRs to TCRs.
(Click to zoom.)
The report also said SPP successfully integrated 9 GW of wind turbines in 2014. Wind produced as much of 33% of the RTO’s energy needs during the year. The market also navigated a winter-weather event with a natural gas supply shortage in March and coal delivery delays through the summer and fall.
Board Chairman Jim Eckelberger said his reading of the report indicated “we have done a good job starting the market, but it seems we’re missing a lot of equipment members have to offer.” He asked MOPC chair Noman Williams of South Central MCN to brief the MOPC and MWG on the report to ensure “good ideas are being pursued” and gather additional feedback on market improvements.
“I disagree with how the MWG has approached this thing. I think rapid-cycle CTs need to be handled differently,” Eckelberger said. “I want to ensure Noman makes sure all sides are addressed.”
NEW YORK — While the New York Public Service Commission may seem to be driving the Reforming the Energy Vision initiative, it is public demand for more control over their energy choices that is the true driver, speakers said at the Infocast New York REV Summit last week.
The challenge, said Jigar Shah, president of Generate Capital, is harnessing the public interest and providing the regulatory structure to enable markets to provide services and technologies that support distributed energy resources (DER).
“Customers do want access to innovative technology, that’s absolutely true, but whether it’s 50% of customers, or 10% of customers, it doesn’t matter. That 10% can create a grassroots movement that’s the type that bowls over politicians. You don’t need 50%,” said Shah, the founder of renewable generator SunEdison.
Shah said the relationship of the utility with the public radically changed as a result of Hurricane Irene and Superstorm Sandy in 2011-12, “with people saying, ‘Wow, I can be out of power for two weeks, and what can I do to solve that problem?’”
That also changed the role of regulators, said Anthony Belsito, a PSC policy advisor. “The former model was regulating from the top down, and it was easy to hang out in the ivory tower,” he said. “… We’ve seen public involvement in the two REV proceedings that so far has been unprecedented.”
O’Brien
David O’Brien, vice president of BRIDGE Energy Group, said New York’s initiative is a start. “Are regulators fully prepared to tackle these issues or to look at the complexity of all this? My feeling is not necessarily,” he said. “But what I really like about REV is its comprehensiveness.”
DeCotis
Paul DeCotis, a director at West Monroe Partners, also expressed doubts. “I have a real concern that there’s a lack of real hard evidence on how to determine the impact [of DER] on cost,” he said.
“There’s a real reason there’s a tension in this room,” said Chris Hickman, CEO of Innovari. “At its core, everybody here knows we better not screw this up.”
