ITC Midwest is overcharging its customers for network upgrades because it isn’t applying for tax breaks to which it is entitled, customers and Iowa officials told FERC last week.
Among the projects affected is Wisconsin Power and Light’s 201-MW Bent Tree Wind Farm in southern Minnesota.
In an unexecuted facilities services agreement filed with FERC, ITC said it needs $38.8 million in network upgrades to support Bent Tree’s generation. It sought to bill WPL $418,020 monthly over 25 years.
WPL asked FERC last week to reject the rates, claiming the charges are excessive because they fail to reflect the “bonus” depreciation that ITC could claim on its federal taxes (ER16-206).
WPL’s sister company, Interstate Power and Light in Iowa, filed a motion to intervene on Nov. 24, saying it could face an identical situation over its Marshalltown Generating Station, which is interconnecting into ITC’s transmission system in Iowa.
“IPL has estimated that ITC Midwest’s annual revenue requirement is roughly $18 million higher in 2015 than it would have been had ITC Midwest taken available bonus depreciation in prior years in which it was eligible to do so. This results in an ITC Midwest transmission rate which is approximately 5% higher, unnecessarily increasing charges to ITC Midwest’s customers — including IPL and its customers,” IPL stated in its motion.
The Iowa Office of Consumer Advocate, Iowa Consumers Coalition, Iowa Utilities Board and Resale Power Group of Iowa have all filed to intervene in the matter.
“The IUB also understands that when bonus depreciation is utilized, it is done so on all capital investments within a given class of assets in a given year, not just selected projects. Thus, ITC Midwest’s choice to not utilize bonus depreciation will affect not only the Bent Tree or Marshall Generating Station network upgrades, but could affect all capital investments in the asset class, including investments elsewhere in the ITC Midwest transmission system, which could directly affect Interstate Power and Light’s customer costs of transmission service,” the Iowa Utilities Board said.
Likewise, the Iowa Consumers Coalition said ITC should “articulate a sound rationale for not electing to take bonus depreciation.”
In recent policy disputes over capacity markets and energy price caps, FirstEnergy and the independent power producers of the Electric Power Supply Association have usually been on the same side.
When EPSA won a federal appeals court ruling voiding FERC’s authority over demand response last year, FirstEnergy asked the commission the same day to prevent DR from being included in PJM’s capacity auction.
But when the Akron-based utility announced last week that it had reached a settlement with the staff of the Public Utilities Commission of Ohio to secure guaranteed rates for several of its merchant plants, the company found itself under attack by many of its former allies.
By Thursday, EPSA had corralled Dynegy, Talen Energy, the PJM Power Providers Group (P3), the Sierra Club of Ohio, AARP and others in a coalition blasting the deal. Dynegy and Talen threatened to sue.
“The fault of FirstEnergy’s inability to compete in Ohio lies with FirstEnergy and it should not be dependent on the citizens and businesses of Ohio to provide a bailout,” said Robert C. Flexon, CEO of Dynegy, which increased its stake in PJM with its purchase of 12,500 MW of generation from Duke Energy and Energy Capital Partners earlier this year. (See Dynegy Wins FERC OK for $6.25B Duke, Energy Capital Partners Generation Deals.)
“Dynegy will pursue all available avenues, including litigation, to prohibit the power purchase agreement from being enacted so as not to compromise the competitive market design, and we strongly encourage the PUCO commissioners to oppose and vote down this adverse anti-market public policy.”
Dynegy said that FirstEnergy is already enjoying the benefits of the wholesale market and shouldn’t need any further assistance.
“Recent market awards indicate that FirstEnergy is already set to receive significant revenue for capacity at all of their Ohio plants for the next three years,” Dynegy said. “According to FirstEnergy’s own data from their recent investor presentation at the Edison Electric Institute’s Financial Conference, FirstEnergy’s fleet has been awarded more than $2.3 billion in revenues over the next three planning years from the PJM capacity auction with all of their generating plants clearing the most recent capacity auctions, which is significantly more than the amount expected at the time of FirstEnergy’s original subsidy request. As part of the award, FirstEnergy’s plants are now obligated to run through May 31, 2019, without the PPAs.”
Reliability Threat
FirstEnergy has said that it needs the income guarantees, in the form of PPAs for its Davis-Besse Nuclear Power Station, the W.H. Sammis coal-fired plant and its share of Ohio Valley Electric Corp.’s generation output, to keep them profitable.
American Electric Power has a similar proposal pending before the Ohio commission. Without the guarantees, the companies say, they might have to retire their plants, threatening system reliability.
Sixteen parties, including PUCO staff and civic groups, signed on to the proposed settlement filed with the commission last Tuesday (14-1297-EL-SSO). Several other organizations, including the Office of the Ohio Consumers’ Counsel, rejected the deal and joined in a motion to reopen the record.
FirstEnergy’s first proposal, which PUCO staff rejected earlier this fall, called for income guarantees for 15 years. The settlement seeks income guarantees for eight years. Ratepayers would make FirstEnergy whole if its generators were not profitable based on their capacity and energy sales in the competitive market.
Although PUCO staff approved the settlement, it still needs approval of the commission. FirstEnergy said it expects the commission to hold hearings on the proposal early next year.
Picking Winners and Losers
Talen joined Dynegy in promising to contest the deal in court if it is approved by the commission.
“As you are aware [PPL, one of Talen’s predecessors] led successful legal challenges in the federal courts against generation subsidy initiatives in New Jersey and Maryland,” Talen spokesman Todd Martin said Thursday. Before PPL’s generation assets were spun off to form Talen, the company won court rulings voiding PPAs obtained by Competitive Power Ventures for two merchant plants. (See CPV Md. Plant Goes Forward Despite FERC Ruling.)
“We believe states with competitive electricity markets must let those markets operate without interference or subsidies, and should not in effect be picking winners and losers,” Martin said.
P3 President Glen Thomas said PUCO staff’s “about face” represents “corporate welfare at its worst.”
“Forcing customers to buy overpriced electricity from uncompetitive plants to deliver windfall profits to FirstEnergy is a holiday offering that only the Grinch could support,” said Trey Addison of AARP Ohio.
“This bailout would leave Ohio locked into outdated and costly coal and nuclear plants, when we should instead be working to transition to a cleaner and more competitive energy system,” said Shannon Fisk, managing attorney with Earthjustice. Fisk was involved in settlement negotiations on behalf of the Sierra Club but withdrew in protest just before Thanksgiving.
Also weighing in was anti-nuclear group Beyond Nuclear, which blasted any deal that would result in the continued operations of FirstEnergy’s Davis-Besse nuclear plant. “The ratepayers of Ohio would be gouged additional billions of dollars on their electricity bills to prop up the uncompetitive Davis-Besse atomic reactor, effectively being forced to fund 20 more years of radioactive Russian roulette at the problem-plagued atomic reactor,” Beyond Nuclear spokesman Kevin Kamps.
$20/MWh Premium
Despite the opposition, UBS analysts predicted last week that the commission will approve the PPAs, which the analysts valued at $68/MWh.
That would be $20 MWh above market prices, based on Ohio’s most recent auction for default service. PUCO in November accepted the results of AEP Ohio’s third wholesale auction to determine the default price through May 2018, at $48.29/MWh. That price will be blended in with result from other auctions to determine the price-to-compare for June 1, 2016, to May 31, 2018. The $48.29 price was the result of a 13-round auction with six competitive suppliers participating.
On Monday, UBS upgraded AEP to “buy” on the expectation that it will win PUCO approval of its deal.
FE: Looking out for Ratepayers
For its part, FirstEnergy said it wasn’t surprised to see the blowback from competitors.
It said it alone is looking out for Ohio’s ratepayers. Although residential ratepayers would pay an extra $3.25 to $3.50 a month during the first year of the deal, the company claims it will produce overall savings of about $560 million. FirstEnergy’s projections, which assume sharply higher natural gas prices in the latter years of the deal, have been widely disputed.
“FirstEnergy has stated from the outset that customers will likely see a monthly charge in the first three years under this arrangement, with the charges converting to credits for customers for the remainder of the eight-year term,” FirstEnergy spokesman Doug Colafella said Friday.
“Out-of-state power producers opposing our plan are betting on sharply higher power prices in Ohio down the road, so naturally they would oppose putting safeguards in place to protect our customers,” Colafella said. “Our proposal is that safeguard.”
ERCOT will add about 9,300 MW of additional capacity by 2019, relieving concerns that the grid’s reserve margins would drop as load continued to grow, according to a new analysis.
The updated 10-year Capacity, Demand and Reserves (CDR) report released last week shows a continuing rise in planning reserve margins — topping 20% in the “next several years.” The Texas grid operator’s reserve margin has stood at 13.75% since December 2010.
The latest CDR shows about 6,250 MW of planned resources have become eligible to be included since the May 2015 report (a net of 3,660 MW after discounting wind nameplate additions). Planning reserve margins increased for all years except 2016.
Gas turbines and wind and solar farms account for much of the expected new capacity. ERCOT said solar capacity should increase from its current 193 MW of installed capacity to 1,789 MW by 2017. Nameplate wind capacity is expected to grow 45% to more than 4,200 MW over the same period, while natural gas capacity is projected to grow 1% to more than 51,000 MW.
ERCOT’s director of system planning, Warren Lasher, said the new generation was responding to the state’s continued growth. “We continue to see the demand for electricity here increase as more people and businesses move into Texas,” he said during a Dec. 1 conference call.
“The generation mix is also growing and changing,” Lasher said. He said some of the capacity growth could be offset by fossil unit retirements as “changing environmental rules begin to take effect.”
ERCOT forecasts a peak of more than 70,500 MW next summer, growing to almost 78,000 MW by summer 2025.
Two years ago, ERCOT was predicting a 20% decrease in its reserve margin. The grid operator had come perilously close to rolling blackouts during a blistering summer of 2011 and plant construction was practically nil.
Recent summer temperatures have not reached predictions and new capacity has come online since then, but ERCOT also revised its planning standards last year. Staff has incorporated growth trends in customer accounts, or premises, to better project regional demand growth.
“We have been able to provide a more accurate look at future demand and energy use,” said Calvin Opheim, ERCOT’s manager of load forecasting and analysis. “I’ve been very happy with how our new forecasting model has performed.”
The latest CDR forecasts peak loads averaging more than 500 MW higher through 2021 than the forecast used for the May CDR. ERCOT said the report is based on average weather over the past 13 years and includes additional electricity demand from a liquefied natural gas facility near Houston, which is scheduled to be fully operational by summer 2019.
The CDR’s data on generation comes from information provided by resource owners.
The report counts as capacity 4,700 MW of coal generation ERCOT expects to retire as a result of EPA’s Clean Power Plan and Regional Haze Program. The draft Regional Haze rule would require scrubber upgrades or retrofits at 12 coal-fired units by 2020. A final rule is expected in several months. The next CDR update is scheduled for release in May 2016.
ERCOT Sets Another New Wind Peak
ERCOT set a new record for wind generation Nov. 25 with 12,971 MW. That accounted for nearly 37% of the grid’s load at the time (9:10 p.m.).
Entergy said last week it is sticking to its plan to close the FitzPatrick nuclear generating station, despite a rescue attempt by New York officials and an offer by Exelon to provide it fuel at cost.
FitzPatrick nuclear plant (Source: Entergy)
Entergy announced last month that competition from low-cost natural gas generation will force it to retire the 838-MW plant in late 2016 or early 2017, when the plant would otherwise be shutting temporarily for refueling. (See Entergy Closing FitzPatrick Nuclear Plant in New York.)
Then came news that New York Gov. Andrew Cuomo wants the Public Service Commission to mandate that 50% of the state’s electricity come from renewable sources by 2030. Cuomo also called for incentives to keep the state’s nuclear plants operating until then. (See Cuomo: 50% Renewables by 2030, Keep Nukes Going.)
At the urging of Cuomo administration officials, Exelon agreed to acquire enough fuel for FitzPatrick and to give Entergy until next June to decide whether to use it based on the clean energy mandate. The PSC said that the proposed “fuel bridge” would allow Entergy to delay its decision without purchasing the $50 million worth of fuel now.
The offers weren’t enough to change Entergy’s mind.
“We have explored every legitimate commercial arrangement that might have changed the decision regarding Fitzpatrick’s retirement,” Entergy spokeswoman Tammy Holden told The Post-Standard. “There is no viable alternative left to consider. The plant will retire at the end of 2016 or early 2017, as we previously announced and have formally advised” the Nuclear Regulatory Commission.
VALLEY FORGE, Pa. — PJM is drafting manual changes to document the parameter adjustment process under Capacity Performance rules.
The process allows a generation operator to request an adjustment if it believes its resource’s physical constraints will prevent it from meeting the parameters assigned by PJM.
Related revisions to Manual 11: Energy and Ancillary Services Market Operations will be presented for endorsement by the Markets and Reliability Committee this month.
At last week’s Operating Committee meeting, the RTO gave a presentation comparing the unit-specific parameter adjustment process with parameter limited schedule (PLS) exceptions.
Unit-specific adjustments would be permitted only because of ongoing, long-term operational limitations, said PJM’s Alpa Jani. Staffing, for example, would not qualify as a physical operating constraint.
PLS exceptions will be used to address short-term, temporary issues such as equipment damage.
Adjustment requests must be submitted to PJM no later than Feb. 28 before the delivery year. If the situation arises after that date, a waiver must be obtained from FERC.
Members also reviewed PJM’s new soak time parameter. Soak time is defined as “the minimum number of hours a unit must run in real-time operations, from the time the unit is put online (breaker closure) to the time the unit is at economic minimum or dispatchable.”
Until the new parameter is added to PJM manuals, adjustment requests similar to the soak time definition will be documented in the minimum run time parameter, and soak time will be noted in PJM internal documentation so it can be updated when a long-term solution is implemented.
In a related matter, the Market Implementation Committee approved an issue charge presented by Bob O’Connell on behalf of PPGI Fund A/B Development to study the process of requesting exceptions to the default parameter limited schedule. (See “Parameter Limited Schedule Exemption Process to be Reviewed” in PJM Market Implementation Committee Briefs.)
The work will be conducted as part of regular MIC meetings and will seek to identify improvements to existing practices for requesting and obtaining PLS exceptions. The group is expected to recommend manual and possible Tariff changes to the MIC by April.
Members Mull Performance Assessment Hour Notifications
PJM also gave the OC a presentation in response to stakeholder questions about performance assessment hours under Capacity Performance.
Generators are subject to steep penalties for failing to meet their capacity obligations during performance assessment hours — periods for which PJM has declared an emergency action. (Base capacity resources are exempt from such penalties except during the June-September summer peak season.)
Members discussed the best way for PJM to communicate the start and stop times of a performance hour. PJM is proposing to post the information in a banner on its Emergency Procedures web page. The notice would direct resource owners to a page where they will be able to find what is expected of them.
Several stakeholders said the information is so crucial that an alert should be placed on the PJM homepage.
PJM Assistant General Counsel Jen Tribulski cautioned that the placement of the notice on the site would not affect market sellers’ responsibility to perform.
“You’re excused from the penalties during the assessment hours if PJM didn’t call on you,” she said. “If we’ve called on you and we have not dispatched you down, you are expected to perform, regardless of whether there’s any notification on our website.”
Also under review is a new signal providing a “desired” basepoint that would be used during performance hours, but it’s not clear whether the signal would recognize a resource’s economic max or unforced capacity commitment.
Members also were told that all units must operate under their local reliability constraints, but having to do so will not excuse them from penalties for not meeting performance requirements.
Charter Approved for Metering Task Force
The committee approved a charter for a task force charged with reviewing metering policies and requirements and implementing best practices.
The group will consider classifications such as real-time telemetry versus revenue metering, generator versus transmission system metering and large generation versus distributed generation applications.
The task force will report recommended manual revisions to the OC. Its work is expected to take six months.
FERC last week rejected SPP’s proposal to create a new class of seams transmission projects, saying its plan was too broadly drawn (ER15-2705).
The commission’s Nov. 30 order said that SPP did not distinguish “the criteria to be deemed a seams transmission project from the criteria to qualify under SPP’s Order No. 1000 interregional processes.” It said the revisions “do not contain any prohibitions or limitations to support SPP’s assertions” that projects eligible for its Order 1000 interregional processes may not be classified and evaluated as seams transmission projects.
FERC rejected SPP’s request to create a new class of seams transmission projects to supplement its approved highway-byway cost allocation.
SPP had proposed seams transmission projects as a new category to fill a gap in its transmission planning. It said the proposal would identify potential transmission projects that “may fall outside the Order 1000 interregional planning process or may not be eligible for cost allocation under SPP’s Order 1000 interregional processes,” such as projects involving external entities that are not neighboring planning regions.
SPP’s current rules designate transmission facilities of 300 kV or above as “highway” facilities whose costs are allocated entirely on a region-wide, postage stamp basis. Facilities between 100 kV and 300 kV are “byway” facilities, with two-thirds of the costs assigned to the host zone and one-third allocated region-wide. Projects below 100 kV are allocated entirely to the host zone.
SPP proposed to define a seams project as one operating at 100 kV or above and costing at least $5 million. It proposed a default regional cost allocation for such projects, with the RTO’s Board of Directors able to choose an alternate allocation at its discretion under certain conditions.
Xcel Energy protested the proposal, saying SPP had not provided “adequate analytical support” for the new category.
FERC agreed, saying the planning process for seams transmission projects “lacks clarity and does not adequately explain” how a seams project would progress from project identification to construction approval. It said SPP’s proposal for projects identified through joint special studies or coordination agreements “does not adequately define the methodology it will use to evaluate the project’s regional benefits.”
FERC said it wasn’t clear that regional review “will be transparent and include sufficient stakeholder involvement.”
The commission said, however, that SPP could make project-by-project filings for non-Order 1000 facilities that “may relate to seams concerns with an associated cost allocation and [justification for] the specific cost allocation.”
SPP legal staff expressed confusion over the ruling during a Dec. 3 meeting of the RTO’s Seams Steering Committee, saying it is “still digesting” the order.
VALLEY FORGE, Pa. — The Planning Committee approved changes to Manual 19 allowing distributed solar generation to be included in the load forecast model.
The group was split in its decision, with 77 voting yes, 18 voting no and 89 members abstaining.
Steve Herling, PJM vice president of planning, said adding distributed solar will lower the load forecast.
PJM’s John Reynolds explained that to create a history of solar generation, planners used the generator attribute tracking system, or GATS.
“We know where they are, how big they are and how long they’ve been there,” Reynolds said of the panels, which Herling noted are the ones not participating in the PJM market.
“We’re not talking about big solar farms,” Herling said.
Planners leveraged that with information from the National Oceanic and Atmospheric Administration to calculate where the sun was in the sky at various times and locations. Each panel was assigned to a weather station for information on cloud cover. Together, the data can estimate how much light was hitting the panels.
That calculation of solar output was aggregated to a zonal number and subtracted from the metered load, Reynolds said, noting that there is virtually no solar metered data available.
The second step was to forecast solar additions by state, for which PJM contracted IHS Energy. Planners took into consideration that some of the new solar likely would be replacing older equipment.
Planners want to break out solar generation because it is growing faster than other behind-the-meter generation and they want to get ahead of the trend.
“It’s going to be important in the future. We’re comfortable making the adjustment now with a procedure that might need refinement,” Herling said. “It might not have a big impact now, but in five years it may. We want a procedure in place now for when solar takes off.” (See “New Load Forecast Model, Related Manual Changes Adopted” in PJM Markets and Reliability Committee Briefs.)
Regardless of PSEG Wheel, 4 Reliability Projects Necessary
Even if Consolidated Edison of New York stops using the so-called PSEG wheel to deliver power into New York City, four baseline upgrades in northern New Jersey are still needed, PJM told Transmission Expansion Advisory Committee members. (See Developer Questions Need for PSE&G Projects Without ‘Wheel.’”)
The four proposals, part of the Regional Transmission Expansion Plan, include the Sewaren storm-hardening project, two sections of the Bergen-Linden Corridor and the Edison Rebuild.
The cost allocation of three of the projects would change significantly in the absence of the wheel.
Currently, Con Ed and East Coast Power each share about half of the cost of the Sewaren upgrade. The change would move all of the cost to ECP.
All affected transmission owners would pay for the two sections of the Bergen-Linden Corridor under the current scenario. Absent the wheel, Con Ed’s allocation would be moved to ECP and Hudson Transmission Partners.
Planners to Recommend ComEd’s Loretto-Wilton Center Project
PJM planners in February will recommend the Board of Managers approve a market efficiency project to relieve constraints on a 345-kV line from Loretto to Wilton Center, Ill.
Proposed by Commonwealth Edison, the $11.5 million project will mitigate sag limitations on the line and replace the station conductor at Wilton Center.
The projected in-service date is 2019.
PJM Continues to Study Effect of Clean Power Plan
PJM is updating its analysis of the economic and reliability impact of EPA’s Clean Power Plan and expects to coordinate its work with MISO.
The primary study years will be 2023 and 2026. PJM also will look at years 2028 and 2030, but with less detailed modeling.
It will examine five mass- and rate-based scenarios for regional as well as individual state compliance.
States have until September to submit their compliance plans or request extensions from EPA.
The work is expected to be complete by July 31, and the TEAC will receive an update at its February meeting.
Just three months after admitting that its push into green energy wasn’t producing returns for shareholders, NRG Energy CEO David Crane announced his resignation. Chief Operating Officer Mauricio Gutierrez will assume the role.
Under Crane’s helm, NRG launched a billion-dollar push into rooftop solar, wind energy and car charging stations. But the company in September announced plans to return to its core conventional generation business. NRG stock has plummeted 60% so far this year.
Crane took over as CEO in 2003, when it was a regional power producer in bankruptcy. It became one of the nation’s largest owners and operators of solar facilities.
NRG Energy said it is selling two power plants for $138 million to reduce debt and improve cash flow.
In one of his last official announcements before resigning, NRG CEO David Crane said the plant sales are part of a “reset” process. “By streamlining our fleet, we can create additional value for our shareholders and meet the needs of our customers with reliable, efficient and economic power,” he said.
NRG is selling its 535-MW, waste coal-fired Seward plant in Pennsylvania to Robindale Energy Services and its 352-MW, natural gas-fired plant in Shelby County, Ill., to The Woodlands-based Rockland Capital. NRG said the two plants would need about $17 million in maintenance in the next three years.
Alliant has said it will close its Dubuque Generating Station on Iowa’s eastern border in June 2017. The Mississippi River plant, which used coal as a fuel source before being converted to gas four years ago, only ran occasionally and was not necessary to maintain system reliability.
Alliant this year settled EPA allegations of Clean Air Act violations, agreeing to close the plant in 2019 or face fines. The facility’s 13 employees will be offered positions at other plants.
Alliant has no plans to sell the property, where a power plant has been in operation for more than a century. If it does, the city of Dubuque has first rights to buy it.
Google announced it has signed six deals on three continents to buy 842 MW of clean energy, bringing its worldwide renewable power purchases to more than 2 GW. Google said it now supplies 37% of its power needs with renewable energy, and the company eventually wants to power all 14 of its data centers with green energy.
“We’re going to get renewable energy any way we can, no matter what it takes,” said Michael Terrell, who leads energy policy and market strategy for Google’s global infrastructure team. The new purchase of solar and wind energy is enough, as Wired pointed out, to power two cities the size of San Francisco.
Duke Energy was involved in several deals with the search giant: One in North Carolina for 61 MW of solar from a project in Rutherford County; and two others in Oklahoma for 401 MW of power.
FirstEnergy named Brian A. Farley vice president of sales, where he will be responsible for strategic planning and day-to-day operations. The division includes the governmental aggregation, large commercial and industrial, and residential and municipal channels.
Farley, who joined FirstEnergy in 1989, most recently was director of wholesale and provider-of-last-resort transactions.
He holds a bachelor’s in electrical engineering from Cleveland State University and a master’s in business administration from Baldwin Wallace University.
The law firm of Frost Brown Todd is opening a Pittsburgh office with the addition of 10 attorneys formerly with law firm Burleson. The attorneys will join the firm’s energy industry practice.
The office is the firm’s 12th and expands its presence to eight states. Kevin Colosimo is the member-in-charge of the new office.
Energy Future Holdings won bankruptcy court approval last week to shed about $30 billion in debt and split into two separate companies.
The bifurcated EFH can exit bankruptcy in a few months, provided that Texas regulators bless the reorganization and the company wins an Internal Revenue Service endorsement of the tax structure behind the deal. Luminant, the company’s unregulated generating business, will go to senior lenders, who are owed about $24 billion. Oncor, the regulated transmission unit, will go to a coalition of lower-ranking creditors and Hunt Consolidated, a Dallas-based energy and real estate company.
With lower debt, the two companies should be in a better position to weather the difficult market conditions that caused the $48 billion leveraged buyout to flounder about seven years after it was completed under the leadership of KKR and TPG Capital. The new plan wipes out the buyout sponsors’ equity.
EFH Agrees to $2M Settlement over New Mexico Uranium Mines
Energy Future Holdings has agreed to pay $2 million to help EPA clean up closed uranium mines it owns in northwest New Mexico.
The agreement, filed Dec. 1, settles a dispute with the Justice Department, which objected to the company’s bankruptcy plans, claiming EFH was trying to skirt its environmental responsibilities. According to court papers filed by the government, EPA found uranium contamination was still present decades later after a now shuttered subsidiary extracted uranium from four New Mexico mines in the 1970s and 80s.
The agency estimated the cost of the cleanup at $23 million.
Luminant Acquiring 2 Gas Plants for $1.6B from NextEra Energy
Luminant, the power generation subsidiary of Energy Future Holdings, is buying two Texas gas-fired power plants for $1.6 billion from NextEra Energy Resources. The deal is expected to close in the first quarter of 2016.
Luminant said its purchase of the 1,912-MW Forney Energy Center and the 1,076-MW Lamar Energy Center in Paris have been approved by the U.S. Bankruptcy Court in Delaware, which is overseeing the reorganization of EFH.
Southern Co. Buys 51% Interest in Texas’ Largest Solar Farm
Southern Co. is buying the controlling interest in a 157-MW planned Texas solar farm, its first solar investment in the Lone Star State.
The Atlanta energy giant said it bought a 51% stake for an undisclosed sum in the planned Roserock solar facility in West Texas near Fort Stockton. Canadian Solar Inc., which is developing the project, will retain 49% ownership through its Recurrent Energy subsidiary.
The Roserock solar farm will provide power to the city of Austin and surrounding areas through a 20-year power purchase agreement with municipally owned Austin Energy. Roserock is one of the largest solar facilities planned in Texas.
El Paso Customers Oppose Proposed $71.5M Rate Increase
About 20 people gave El Paso Electric’s proposed $71.5 million rate increase a thumbs down at an El Paso City Council hearing Dec. 2. The utility is seeking a 10.15% rate of return.
Most of those speaking at the hearing were solar advocates. They included homeowners with solar rooftop systems who said their rates would increase more than other residential customers, and solar system installers who said the utility’s proposed new rate class for residential solar customers would discourage consumers from embracing renewable energy.
Representatives of Western Refining’s El Paso refinery, the utility’s largest customer, said the proposed increase has prompted the company to begin exploring the possibility of generating its own electricity.
Aksamit Resource Management announced plans to build three wind farms generating 449 MW in southeastern Nebraska, representing a $725 million investment.
The developer said it has filed with SPP for permission to hook up two of the wind farms to transmission lines owned by the Nebraska Public Power District. The projects include a 150-turbine farm spread over 30,000 acres with a capacity of 300 MW and a 76-MW project with 40 turbines on 8,000 acres.
Aksamit said a third project, a 40-turbine farm in Saline County that can produce 73 MW, will be up and running within the next two years.
CARMEL, Ind. — MISO would reduce the price tag to enter its generator interconnection queue and provide “off ramps” for canceled projects under a final proposal presented Monday to the Planning Advisory Committee.
RTO officials said they reduced a proposed $60,000 refundable deposit for study models based on stakeholder feedback. Instead, interconnection customers would have to pay a non-refundable $5,000 study deposit.
Vikram Godbole, senior manager of MISO’s generator interconnection planning group, said the non-refundable charge facilitates trust between the RTO and interconnection customers. “We need to have a relationship with interconnection customers before providing models because there’s a lot of non-public information in these models,” Godbole explained in a presentation during a special PAC meeting.
Discussions on the proposed reforms will continue at the Dec. 16 PAC meeting, after which the proposal will open to a final round of stakeholder comments. MISO plans to file Tariff changes by the end of the year, Godbole said.
In addition to reducing the study fee, MISO has also cut its proposed M4 milestone by half; the new M4 cap will be set at $5,000/MW instead of $10,000/MW. The proposed $2,000/MW floor remains intact. MISO said it was responding to stakeholder comments that existing milestones are high and act as a barrier to entry.
Additionally, MISO has relaxed some rigidity surrounding its queue, allowing interconnection customers to receive M2, M3 and M4 refunds on projects that withdraw before the first decision point, which doesn’t occur until customers have the results of a system impact study.
Customers can also request provisional interconnection service up until their first decision point. Interconnection customers that request provisional interconnection service can now cancel their request, forgoing money spent on studies up to the cancellation date, and enter the definitive planning phase cycle.
“I think what we’ve done here is made this more flexible. If you want to proceed, that’s fine. If you don’t want to proceed, that’s fine too,” Godbole said. “The fact that we have these off-ramps built in; we expect that some interconnection customers will use them. I’m hoping these off-ramps will really help interconnection customers decide whether to get their M2 back.” MISO’s current queue doesn’t allow for the refund of M2 payment for withdrawing projects.
MISO has also eliminated the potential for restudies after customers execute a generation interconnection agreement.
“If any conditions change, we’re not going to rope you back into a restudy,” Godbole said.
“With the queue reform, one of the main goals was certainty,” MISO Director of Interconnection and Planning Tim Aliff said, explaining that if interconnection customers “have done their homework” on project feasibility and economics before entering the queue, M2, M3 and M4 payments will come back to them.
Aliff added that projects that withdraw and forfeit milestone payments will benefit other projects that complete generation interconnect agreements. “Your costs are offset by what others have left in the bucket,” he said.
Godbole said MISO has explored three transition options to the new queue rules, which are expected to take effect in February. In all three, MISO will grant existing projects priority over projects that have yet to join the queue. Interconnection customers will have the opportunity to request provisional agreements during the transition period to the new queue rules.
Godbole said MISO will produce a study calendar of pertinent dates after a transition plan is finalized.
“It’s in our best interests to do everything as quickly as possible,” Godbole said. He added that MISO plans to file Tariff changes by the end of the year. Discussions on queue reform will continue on Dec. 16’s Planning Advisory Committee where no formal action is anticipated. The queue reform proposal will then move into a stakeholder comment period.
WASHINGTON — Having achieved a settlement with Mayor Muriel Bowser’s administration, Exelon and Pepco Holdings Inc. tried to persuade the D.C. Public Service Commission over the course of three days of hearings last week that their nearly $7 billion merger is now in the public interest.
Carim Khouzami, chief integration officer for Exelon, and David Velazquez, Pepco’s executive vice president for power delivery, were among those whom Chairman Betty Ann Kane and Commissioner Joanne Doddy Fort questioned on the details of the settlement. Commissioner Willie Phillips did not ask any questions.
Regulators unanimously rejected the deal in August, finding that it was not in the public interest. The Bowser administration brokered the settlement, which was filed in October. D.C. is the last jurisdiction needed to close the deal, with New Jersey, Maryland, Virginia, Delaware and FERC all having given their approval. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
“In retrospect, we realize that our failure to present a settlement agreement made it a very difficult task for this commission to find the merger was in the public interest,” Peter Meier, vice president of legal services for Pepco, said in an opening statement. “We’re here today because a settlement was agreed to.”
Rate Impact
The D.C. commissioners questioned the officials about the logistics of the settlement: how rate credits would appear on customers’ bills, what the structure of the new company would look like and whose overdue bills would be forgiven.
DC Commissioners at the hearing, left to right: Commissioner Joanne Doddy Fort, Chairman Betty Ann Kane, Commissioner Willie L Phillips (Source DC PSC)
Kane was interested in how the promised credits would protect against rate shock. Exelon promised $14 million in direct credits to residential customers and $25.6 million in credits to offset future rate increases the company expects to file. Kane estimated that the distribution portion of customers’ bills would jump 20 to 30% in 2019 after the $25.6 million ran out.
“Ultimately the rate cases are the determination of the commission [and] what they see as reasonable and prudent,” Khouzami said. But “with this commitment, $25.6 million worth of rates will never be paid by customers.” Without the merger, Pepco would still seek similar levels of rate increases and “customers would still be subject to that without an offset,” he said.
Fort asked how $5.2 million in contributions to district workforce development programs constituted a “direct and tangible benefit” to ratepayers, required to prove the merger is in the public interest.
In a pre-hearing brief, Velazquez said the contribution will provide training to district residents in “sustainable jobs.”
At the hearing, however, the executives were vague about the types of jobs residents would be trained for in the workforce development programs, and what exactly was meant by “sustainable.”
Residents would get “a skill set needed to get a good-paying, secure, sustainable job in the district that will help benefit them for years to come, so I think there’s a true benefit here,” Khouzami said. The companies have not made a firm commitment to hiring residents who participate in the programs, he said in response to a question from Fort. The funds are “really intended to provide the job training needed so that individuals can actually select the job that they want, whether it’s at Pepco or somewhere else in the district.”
“It is my hope that through this program, we’ll also be working with the district and having a discussion about the type of jobs that Pepco will need as we move forward with the grid of the future,” Velazquez said. “These are jobs that are related to helping drive renewable energy, driving energy efficiency, driving microgrids, driving the smart grid. All those things are going to help create a more sustainable electric grid and a more sustainable use of electric energy.”
District Official also Questioned
The director of the district’s Department of Energy and Environment, Tommy Wells, was the first witness questioned by the commission on Wednesday.
The commissioners peppered Wells with questions about how money in the district’s Renewable Energy Development Fund and the Sustainable Energy Trust Fund has been used to make up for shortfalls in the district’s general fund. Under the settlement, Exelon will contribute $3.5 million to each fund.
DC’s Tommy Wells testifies (Source DC PSC)
Wells admitted that transfers from the energy funds, which must be approved by the D.C. Council, are not prohibited under the settlement. But, Wells said, “it is completely in alignment with the plans and vision for this administration to expend those funds exactly as they’ve been negotiated.
“I can’t speak to the whims of the council, but I believe the council” will respect the intent of the administration, Wells said.
Wells, like Khouzami and Velazquez, was also vague about the workforce development funds. Fort asked what agency would receive them.
“That’s a great question because we’re working on that now,” Wells answered. He mentioned the University of the District of Columbia and the Department of Employment Services as possible candidates, but it’s not clear yet if the money would even go to the government, he said. If it does, City Administrator Rashad Young would ultimately decide which agency receives the funds, he said.
Wells also said “sustainable” jobs was meant to refer to both green and long-lasting jobs.
Wells was questioned first at the request of the D.C. government, as he had to catch an afternoon flight to Paris, where he accepted an award for green energy on behalf of the district from the C40 Cities Climate Leadership Group. The group, comprising 78 cities around the world, honored the district for its 20-year power purchase agreement with Iberdrola Renewables that will supply 30% of the government’s electricity through wind power.
The announcement of the award — which was followed by applause in the room — came during the hearing on Thursday, as Pepco cross examined Bruce Burcat, executive director of the Mid-Atlantic Renewable Energy Coalition. Iberdrola is a member of MAREC, which opposes the merger.
Looking Ahead
With the administration and the district’s public advocate on its side, Exelon’s chances appear to hinge on winning over Kane or Fort.
Phillips had issued a partial dissent in August, saying that he would have supported a merger that would have brought “benefits for ratepayers, the local economy and the environment.”
The settlement brokered by the Bowser administration includes $78 million in customer benefits, up from $14 million in the company’s original offer.
Post-hearing briefs are due Dec. 16, with reply briefs due Dec. 23. The record will then close, starting the countdown to a commission decision.
On Monday, four councilmembers sent an 11-page letter to the PSC urging it to reject the deal, saying it offers “short-term benefits that in the long-term have detrimental costs.”
