The head of the nuclear industry lobby told Wall Street analysts last week that more of the nation’s nuclear fleet will retire prematurely, hurting efforts to meet carbon emission goals, without immediate action by federal and state policymakers to improve their finances.
Marvin Fertel, CEO of the Nuclear Energy Institute, noted that eight reactors have closed or announced closings in the last three years, half of them citing market issues.
Marvin Fertel, Nuclear Energy Institute
NEI says the nation’s 99 nuclear plants generate 63% of the country’s zero-carbon power. In 2015, the group says, nuclear plants had a record 91.9% capacity factor and reduced the average refueling outage to 36 days.
“It simply defies logic to shut down carbon-free nuclear plants, each of which employs 600-plus people, and replace them with natural gas plants employing maybe 30 people and whose cost of producing electricity is nearly 60% higher,” Fertel said during the group’s annual meeting with financial analysts Thursday.
Policymakers in Ohio and Illinois are considering actions that could bolster the finances of nuclear plants, whose revenues have been pinched as low natural gas prices have reduced clearing prices in wholesale energy markets.
New York utilities would be required to procure more than 15% of their forecasted load in 2020 from nuclear plants under a proposal last month by Gov. Andrew Cuomo. (See New York Would Require Nuclear Power Mandate, Subsidy.)
PJM’s Capacity Performance rules, approved by FERC last year, could boost capacity revenues over time.
But Fertel said aid isn’t coming quickly enough. “We have no time to waste. If we do not demonstrate a greater sense of urgency about addressing the problems in the electricity markets, we will lose more nuclear plants,” he said.
New York Gov. Andrew Cuomo has accused NRG Energy of reneging on an agreement to repower the shuttered Dunkirk coal-fired power plant and ordered state regulators to investigate whether consumers were “defrauded.”
In a letter to the Public Service Commission on Tuesday, Cuomo said its report should determine why the repowering was not done, the financial impact on consumers and whether NRG should be allowed to operate in the state.
“New York welcomes fair-minded and public-oriented independent power producers as important members of our economic community and our electric industry. We cannot, however, tolerate companies that take advantage of consumers to achieve ill-gotten gains,” Cuomo wrote.
Dunkirk power plant (Source: NRG Energy)
Cuomo said NRG received $110 million from National Grid ratepayers from 2012 to 2015 to keep Dunkirk operating after it announced its decision to mothball the plant. Repowering to natural gas was supposed to have been completed last September.
NRG responded on Thursday that it is “very surprised” by the letter and said Cuomo’s assertion “contradicts the facts.”
“NRG’s Dunkirk facility kept the lights on in Western New York for the past two years, based on a 2012 contract approved by the governor’s own Public Service Commission. Over that time, our Dunkirk employees delivered near flawless performance — at the price agreed to in advance by the state,” company spokesman David Gaier said in a statement.
“NRG has invested in the Dunkirk facility and the local community, and we made more than $16 million in property tax payments over the past two years. We stand by everything we’ve done to support the power grid and ratepayers in Western New York. We’ll respond more fully in the days ahead with the facts,” he continued.
Repowering of Dunkirk to natural gas was approved by the PSC after the company negotiated financial incentives with the governor. The plant ceased operations on Dec. 31 at the conclusion of a reliability support services agreement that paid it above-market rates to remain operating to ensure grid reliability.
However, the repowering agreement was challenged in federal court by another generator who claimed it illegally suppressed wholesale prices in New York. NRG put the repowering project on hold, saying the lawsuit created too much uncertainty to proceed. (See NRG Plant Closures Could Impact Reliability in NY.)
Cuomo said he wants the PSC report “as soon as practicable.”
MISO’s System Operation Training Working Group (SOTWG) is at risk of disbanding after a request for new leadership went unanswered. The working group has lacked a chairperson since former chair Steve Zimmerman stepped down at the end of December.
“It looks like if we’re not going to get any stakeholder volunteers for leadership, this might be an opportunity … to move this into a MISO user group,” Reliability Subcommittee Chair Tony Jankowski said during a Feb. 10 meeting. Although user groups don’t participate in policy decisions, he said the RSC would still provide a forum for stakeholders on training operations should the change be made.
“If we move to the user group, it would be temporary, for me at least, and if we get way off-track or out-of-kilter, we may have to move it back to more stakeholder-driven than a user group. It isn’t going to happen overnight, but truly this is a call-out,” Jankowski said. “There’s a lot of groups and organizations that attend these meetings. Stakeholder leadership, even at a working-group level, is a valuable thing. We’re just short of that stakeholder participation, and we need to have that.”
He added that the leadership vacancy should be reported to MISO’s Steering Committee, which could order the change. He didn’t put a timeline on it but urged participants to come forward with nominations before that happens.
The working group is charged with identifying and meeting MISO stakeholder training needs. Last year, it worked with MISO to publish an online training catalog, developed training sessions on natural gas coordination and made NERC continuing education classes available. The SOTWG said it trained 2,015 people and provided about 384 hours of continuing education in 2015.
SOTWG Vice Chair Will Behnke said participation was low during 2015 training sessions, with people signing up for courses and often failing to attend. He reminded the subcommittee that the courses are provided free of charge.
“I really strongly recommend that folks send someone out to attend these meetings,” Behnke said.
2016 Priorities
Jankowski outlined issues the RSC plans to address in 2016.
He said the RSC began asking stakeholders to compile a list of reliability issues in January and identified frequency response as an issue that “needs to be kept alive.”
Although MISO should be compliant with the new NERC standard taking effect April 1, Jankowski said he’d like to follow up on the issue because MISO’s renewable power growth could affect how operations and emergency protocols work. (See “MISO Ready for Frequency Response Standard,” MISO Reliability Subcommittee Briefs.)
He added that the issue needs to be examined at length before action is taken.
“We think it’s premature to spend any appreciable time on revamping how reliability works. … It’s too difficult when you don’t know what you’re chasing,” he said.
Bill SeDoris, director of MISO integration for Northern Indiana Public Service Co., asked that the RSC keep an eye on how the SPP and MISO settlement payments play out after the elimination of the hurdle rate.
Power Restoration Drill
The RSC was reminded that MISO’s 2016 spring power system restoration drill is scheduled for March 23.
AUSTIN, Texas — Making his first presentation to ERCOT’s Board of Directors as CEO, Bill Magness alluded to the unseasonably warm Texas weather as a calming influence during his first month on the job.
“This beautiful, fantastic weather [is] great for my nerves starting out as ERCOT’s CEO,” Magness said. “But it’s terrible for revenues.”
Magness said the milder-than-expected weather resulted in a $1.3 million shortfall in system administration fees for 2015, a major reason why net revenues for the year were $1.8 million below budget.
Magness also reported $2.7 million in over-budget costs for employee benefits and additional responsibilities under NERC’s new transmission-planning standard.
The increased costs were partially offset by lower interest and technology expenses.
“We had unusually high benefit costs … a number we’re really not happy about,” Magness said.
ERCOT’s 2016 operating budget will use a more “granular” load-forecasting methodology that will produce better results, Magness said. Staff recorded a -0.8% error in forecasting load last year, “and we think from an operations standpoint, [the new methodology] helps us better track our finances,” he said.
Warmest Winter Ever?
ERCOT meteorologist Chris Coleman told the board the “crazy winter” Magness lamented can be attributed to El Niño, the warming climate pattern in the tropical Pacific Ocean, and he said there’s a “greater potential for a warmer forecast” than a colder one for the remainder of the winter.
“This is the strongest [El Niño] has been at this point in the cycle ever. It will go down as one of the two strongest ever,” surpassed only by the 1997-98 El Niño, Coleman said. “This one is finishing stronger. We could be seeing our warmest winter ever.”
Austin has seen just three freezes since Nov. 1 after having recorded 28 over the previous two winters and has spent less than four hours at or below freezing this winter. Temperatures have yet to dip below 31 degrees so far, the warmest minimum temperature recorded through January in 20 years.
Looking ahead, Coleman projects a wet winter for much of Texas and an above-average number of ice events. He said the state’s northwestern portions could see a wet spring, but it will be drier elsewhere, which could lead to a return of drought conditions.
ERCOT’s next seasonal assessment of resource adequacy, early next month, will include an updated weather forecast.
ERCOT Unveils New Logo in State of Grid Report
ERCOT released its annual State of the Grid report Feb. 9, highlighting a new fluid, open-ended logo that it said reflects “the perfect flow of power on a high-demand summer day.” The report details ERCOT’s record in each of five areas: accountability, leadership, innovation, trust and expertise. It also provides updates on a number of initiatives and milestones, including successfully managing the first system peaks since 2011 and integrating the nation’s largest amount of wind capacity.
IMM Says Real-Time Prices Dropped
ERCOT’s Independent Market Monitor said real-time energy prices were down 34% in 2015, averaging $26.77/MWh compared to $40.64/MWh the year before, which began with a cold winter.
IMM Director Beth Garza said ERCOT’s implied heat rate indicated a number of inefficient units were being used to meet demand. Real-time and day-ahead heat rates peaked at 13.94 MBtu/MWh and 20.28 MBtu/MWh, respectively, in August, when ERCOT recorded its five highest daily demand peaks ever.
Special Meeting to Replace Director
The board unanimously approved staff’s recommendation for a special meeting to select an unaffiliated director before June 30. ERCOT bylaws call for five unaffiliated directors on the board, but the Texas grid operator’s Nominating Committee will not be able to meet and select a candidate to present to corporate members before June 30, when Jorge Bermudez’s second term expires. He will seek re-election for a third and final term.
The board also re-elected Craven Crowell and Judy Walsh as chairman and vice chair, respectively, and approved ERCOT’s two newest officers: Chad Seely, who replaced Magness as general counsel, and Senior Vice President and COO Cheryl Mele.
Randa Stephenson was re-confirmed as Technical Advisory Committee chair. Previous vice-chair Adrianne Brandt recently left Austin Energy for San Antonio’s CPS Energy; she will have to be re-elected to her position by TAC members before she can be confirmed by the board.
Finally, the board welcomed five new segment alternates: American Electric Power’s Wade Smith (Investor-Owned Utilities), DC Energy Texas’ Seth Cochran (Independent Power Marketers), Chapparal Steel Midlothian’s Sam Harper (Industrial Consumers), Invenergy Energy Management’s Mark Soutter (Independent Generators) and CenterPoint Energy’s Kenneth Mercado, (Investor-Owned Utilities).
Consent Agenda Passes Unanimously
The board unanimously passed its consent agenda, approving eight protocol revision requests and a nodal operating guide revision (NOGRR147, Reactive Power Testing Requirements) that were previously endorsed by the TAC. (See “Protocol Revision Requests OK’d,” ERCOT: No Consensus on Operating Reserve Changes.)
Closure of the FitzPatrick nuclear plant will leave New York at least 325 MW short of its generation requirement by 2019, according to a new assessment from NYISO.
FitzPatrick Nuclear Plant (Source Entergy)
The assessment, released Thursday, was ordered following Entergy’s announcement last year that the 882-MW plant would close at the end of its current fueling cycle, later this year or early in 2017.
“The resource deficiency equates to approximately 325 MW statewide but would likely require more than 325 MW of new or retained capacity resources to resolve, depending on forced outage rates and the location of the resources,” the assessment says.
NYISO is requesting solicitations for a “gap solution” from market participants that may include generation, transmission or demand response to address the shortfall. The RTO normally addresses reliability needs biennially but said the expected shortfall in 2019 requires action now.
About 2,600 MW of capacity is expected to leave the New York fleet by mid-2017. Besides FitzPatrick, NYISO has already lost, or is expecting to lose, the coal-fired plants Dunkirk, Cayuga and Huntley, along with the Ginna nuclear plant. (See Entergy Rebuffs Cuomo Offer; FitzPatrick Closing Unchanged.)
Currently inactive or close to deactivation are a 50-MW biomass plant in Niagara Falls and several gas peaking units in New York City. (See TransCanada may Mothball 3 NYC Gas Peakers.)
An 820-MW gas-fired plant in southern New York is expected to be in service by March 2018 and several transmission upgrades planned by mid-2020 are expected to mitigate the plant closures.
The assessment says new resources would be less effective to the state overall if they were added to Zone A in western New York. “Due to transmission system limitations between Zones A and B, capacity added in Zone A is not as effective as capacity added in other locations, unless that capacity also improves the transfer limitations,” it states.
Zone A is a relatively large area around Buffalo. Zone B is a narrow strip that runs from the Pennsylvania border to Lake Ontario and includes three nuclear power plants.
FitzPatrick Inspection
On Wednesday, meanwhile, the Nuclear Regulatory Commission released an inspection report that identified two violations of “very low safety significance” at FitzPatrick.
In November the plant took one of its backup emergency diesel generators offline while another backup generator was being serviced. In December, Entergy failed to tell NRC when a secondary containment ventilation system was inoperable.
The report, which summarized NRC’s three-month inspection ending Dec. 31, also included a third violation, self-reported by Entergy and considered of low significance. The company said it discovered it was operating during its previous fuel cycle, from October 2013 to October 2015 without the required number of safety relief valves.
Cold-weather testing continued into the second week of January due to the region experiencing one of the mildest Decembers on record.
The cost of the testing was cheaper than the previous year — $3.4 million compared with $4.9 million.
Two out of three eligible units declined to test, which Operating Committee Chair Mike Bryson said was a good thing because they would have been turned down anyway because of the warm weather. Some units have indicated they are going to test themselves, he said.
The success rate by unit was 97%; by megawatt, it was 98%.
The largest cause of failures, at 38%, was liquid fuel handling problems, followed by control system issues (15%).
Session will Study Transmission, Energy Scheduling Practices
An educational session will be held Feb. 24 on proposed changes to PJM’s regional transmission and energy scheduling practices.
The updates stem from the alignment of the gas-electric market timeline and generator offer flexibility proposals.
The changes add a five-minute “shotgun” start window for the hourly spot-in product — spot market imports — in which all reservations will be considered simultaneously.
“This process is going to give everybody a better shot at receiving the request they submitted,” PJM’s Chris Pacella said.
PJM Prepares for Annual Security Drill
PJM is asking members wanting to take part in the annual Grid Security Disturbance Drill to respond by March 11. The drill will be held on Nov. 9.
Transmission owners will participate in the drill from their workplaces. Generation owners will take part in a tabletop exercise at PJM.
The purpose of the drill is to assess the RTO’s ability to respond to disruptions caused by coordinated cyber and physical attacks and restore the grid to normal operations.
A kick-off meeting will be held in May. For more information, email BCP_Mailbox@pjm.com.
The Mixed Oxide Fuel Fabrication Facility to turn weapons-grade plutonium into commercial reactor fuel is on the chopping block as the Obama administration has proposed switching to an alternative disposal method. South Carolina officials say they will sue the federal government for missing deadlines and to force it to pay contractual penalties of $1 million a day for failing to complete the project.
The U.S. Energy Department has already spent $4.5 billion on the half-built plant at the Savannah River Site near Aiken, S.C., designed to dispose 34 tons of plutonium as part of international weapons agreements. The MOX project is now estimated to cost between $9.4 billion and $21 billion, and may not begin operations until 2040.
A new department budget calls for spending $285 million to blend the plutonium with other materials and then dispose of it underground in New Mexico.
DOE Announces $18 Million in Grants for Solar-Battery Storage
The Energy Department is devoting $18 million to help develop ways to integrate solar generation and battery storage in order to overcome the challenge of matching the intermittent production of solar power to market demands.
The grants will go to Austin Energy, Carnegie Mellon University, Commonwealth Edison, the Electric Power Research Institute, Hawaiian Electric and the Boston-based Fraunhofer Center for Sustainable Energy Systems.
The money will go toward developing new integrated photovoltaic energy generation and storage projects using Internet-capable inverters that will join solar arrays, smart buildings and appliances, and utility communication and control systems.
Solar Companies Form First National Trade Association
Seven energy companies have joined to create a national trade association to promote community solar projects, which are financed by subscribers who receive solar energy credits on their bills.
“Community solar is the necessary next step to bringing solar to the majority of Americans for whom solar is not yet an option,” said Jeff Cramer, the executive director of the new group, the Coalition for Community Solar Access.
The coalition’s founding leadership includes Clean Energy Collective, Community Energy, Ecoplexus, Ethical Electric, First Solar, NRG Energy and Recurrent Energy.
Despite NRC OK, No Plans to Build South Texas Nukes
The Nuclear Regulatory Commission approved licenses to build two new reactors at the South Texas Project nuclear plant southwest of Houston, but NRG Energy and its partners have no plans to build them because of competition from cheaper power suppliers.
The partnership is continuing to look for new U.S. investors to eventually move the stalled project forward, said NRG spokesman David Knox. The company said five years ago it wasn’t investing any more money in the expansion, which then had an estimated cost of about $14 billion.
The existing South Texas Project’s two reactors are owned jointly by NRG, Austin Energy and San Antonio’s CPS Energy. NRG has sought additional partners in the expansion since CPS Energy, once a 50% partner, reduced its stake to 7.6%.
The U.S. Army has signed a 30-year contract with Apex Clean Energy to provide 65 MW of solar and wind energy at Fort Hood in Texas. The Army will pay Apex as much as $497.4 million over the life of the deal, about $168 million less than what it would pay for power from the traditional electricity grid, according to the Defense Logistics Agency.
Officials broke ground in January at the Army installation 75 miles north of Austin on a 132-acre solar farm that includes 63,000 panels. The solar project is paired with an investment in a Panhandle wind farm.
The military, the single largest consumer of energy in the U.S., is dedicating at least $7 billion to renewable energy projects, part of the Obama administration’s efforts to emphasize alternative sources of energy.
FERC Infrastructure Report Shows Solar 2015 Project Leader
A report from FERC’s Office of Energy Projects shows that solar generation led the way for new generation in the U.S. in 2015, followed by wind and then natural gas, on the basis of number of projects. Solar accounted for 248 projects but ranked third behind wind and natural gas in terms of capacity.
Wind came in second with 69 projects, but the combined installed capacity of nearly 8,000 MW led the pack. Natural gas came in third in both number of projects (50) and capacity (6,000 MW).
Combined, solar, wind and natural gas accounted for nearly 97% of all new capacity installed in the U.S. in 2015.
Solar and Wind to Account for 6% of Generation in 2016
Utility-scale wind and solar will account for 6% of electric generation in the U.S. in the coming year, according to a report from the Energy Information Administration. Although solar’s share is less than 1%, it represents a 28% increase over 2015.
EIA did not count distributed solar, the most common type among residential and small business customers. If small-scale rooftop systems were included, solar would supply about 1.2% of 2016 generation.
Wind and hydro will come in at 5.2% and 6% respectively, according to EIA. When biomass and geothermal power are included, renewable energy overall is expected to account for 14.5% of power generation in 2016.
FERC last week ordered PennEast Pipeline to provide more information on its proposed 110-mile natural gas pipeline that would run from Pennsylvania under the Delaware River and into New Jersey, saying it wants to know more about how the pipeline would affect several nature preserves.
FERC is preparing its environmental impact statement for the pipeline proposal and wants to know how PennEast would protect wildlife and how it would mitigate any effect on wetlands.
Pipeline opponents saw FERC’s demand as a win and called on the federal agency to suspend its review of the project. “FERC’s letter demonstrates once again that the information that PennEast has submitted to date is incomplete and inaccurate,” said Michael Pisarro of the Stony Brook-Millstone Watershed Association.
VALLEY FORGE, Pa. — Stu Bresler, senior vice president for market operations, told the Market Implementation Committee Wednesday that discussions with market participants and among staff have highlighted the need for manual changes to clarify rules regarding capacity bilateral transactions.
“Neither the Tariff nor the manual provides clarity about those transactions,” said Bresler, delineating them as unit-specific, auction-specific and locational unforced capacity.
He explained that in such transactions, the performance obligation remains with the seller, while the title to the megawatts for the capacity is transferred to the buyer. If the resource earns bonus credits, they go to the buyer.
At issue is the physical nature of the transactions, Bresler said.
“A court could say it’s not a physical transfer of megawatts, it’s just an assignment of receivables,” he said. “The more the physicality of a transaction is questionable, the more likely in a bankruptcy proceeding that the credit associated with that would be yanked away from the buyer and included in the bankruptcy estate.”
A second issue involves the fact that a buyer indemnifies PJM against a seller’s non-performance. “What happens if the seller in the transaction replaces the resource that was the subject of the transaction in the first place?” Bresler said. “What should the replacement rules be?”
Bresler suggested that the issue be expedited.
After Months of Debate, Data Confidentiality Rule Changes Endorsed
With 16 opposing votes, members endorsed changes to data confidentiality rules that have been the subject of debate since June. (See “Market Data Confidentiality Rule Change Gets First Reading,” PJM Market Implementation Briefs.)
Current rules prohibit PJM from talking about certain information even after it’s been disclosed publicly. At the heart of the deliberation has been how to provide PJM the ability to discuss situations such as generator outages while at the same time not disclosing commercially sensitive information.
The proposal allows PJM to release and discuss:
Information on individual generation outages involving an unusual operating condition on the transmission system such as a severe weather event;
The amount of demand response in an area no smaller than three ZIP codes (specific offers or suppliers would remain confidential);
The total amount of capacity offered and cleared, aggregated by transmission zone;
Uplift payments in an area no smaller than a transmission zone, and for no shorter a time period than one operating day;
Aggregated statistics related to the results of the three pivotal supplier test; and
Data made public by a PJM member or a state or federal regulator.
One minor change was made since the first reading. A sentence was added to specify the circumstances in which DR information would be released. The revised language allows such disclosures for incidents including, but not limited to, a severe event on the transmission system, a severe weather event, the formation of a closed-loop interface or the need for a transmission system upgrade.
Operating Parameters to be Subject of Special Session
An educational session will be held Feb. 24 to explain updated operating parameter definitions.
A number of operating parameters whose definitions appear only in the eMKT/Markets Gateway Users Guide have led to confusion among members about what values should be entered.
PJM also wants to clarify several terms in Manual 15.
A new “soak time” parameter has been proposed that would define the minimum length of time a unit must run to reach its economic minimum.
PJM and its Independent Market Monitor asked FERC Thursday to revise Capacity Performance rules to address concerns that generators might ignore dispatch instructions to avoid penalties.
FERC’s June 2015 order approving PJM’s tougher capacity requirements directed the RTO to eliminate language that would allow generator parameter limitations to be used as an excuse for nonperformance (ER15-623, EL15-29). The order argued that if resources were held only to parameter limits based on their physical characteristics, those that were less flexible would be able to avoid nonperformance charges more readily than more flexible units. (See What is Changing in PJM’s Proposal?)
However, PJM said in a Dec. 22 informational filing that eliminating any consideration of parameter limits from penalty calculations might lead some generators to self-schedule at maximum output in anticipation of a performance assessment hour, ignoring economic dispatch.
In a joint statement last week, PJM and the Monitor asked the commission to allow consideration of parameter limits but incorporate the Monitor’s recommendation that the limits be based on original equipment manufacturer (OEM) specifications rather than on historical performance data. This, they said, would ensure that resources not escape penalties “as a result of economic decisions about maintenance and investment.”
Under the proposal, resources would not face nonperformance charges if their operating parameters complied with the OEM limits and they followed dispatch orders. Resources that offered parameters less flexible than the OEM specifications would be ineligible for uplift and could be vulnerable to penalties.
They also asked FERC to approve the Monitor’s proposal that parameter limits be defined for ramp rate and boiler temperature retention times.
DTE Energy reported 2015 net income of $727 million ($4.05/share), a 20% decline from 2014’s $905 million ($5.10/share). The company’s $80 million net income for the fourth quarter was off 73% from the $299 million reported a year earlier.
However, the company reported that 2015’s operating earnings, which exclude non-recurring items, certain adjustments and discontinued operations, totaled $863 million ($4.82/share), a 5.8% increase over 2014’s $816 million ($4.60/share).
The Detroit company blamed its lower 2015 earnings on non-utility business lines — power and industrial projects, natural gas pipelines, gathering and storage, and energy marketing and trading — where earnings dropped 65.6% to $101 million, due in part to a $22 million loss by the trading unit. Earnings for DTE Electric rose 3% to $542 million for the year.
Operating revenues were $10.3 billion for the year, down from $12.3 billion in 2014. At the same time, DTE trimmed operating expenses to $9.1 billion in 2015 from $10.7 billion a year earlier.
Peter Oleksiak, DTE senior vice president and CFO, said the company forecast a mild winter before the fourth quarter began and went into a “lean mode,” paring down expenses.
During a Feb. 10 conference call, DTE CEO Gerry Anderson said some gas storage and pipeline projects across the industry might be “sub-investment grade.” He said the company will monitor its own investments in gas storage and pipelines but would be open to purchasing other companies’ assets if they were offered. He said that DTE’s industrial segment lagged in 2015 because of a weak steel market, but overall he saw no problems in the balance of the company’s portfolio.
The company paid dividends of $2.84/share for the year, up from $2.69/share in 2014.
Among 2015’s bright spots, Anderson said in a press release, were the company’s completion of more than 100 reliability improvement projects and its success in meeting Michigan’s 2015 target by sourcing 10% of electricity production from renewables.
“DTE made great strides in 2015, both operationally and financially,” Anderson said. “The year brought significant improvements … contributing to the best overall reliability performance in eight years.”
Anderson said DTE would continue to focus on reliability and pledged to invest $6.5 billion in distribution infrastructure over the next 10 years. DTE also said it plans to begin construction this year on what it described as the largest utility-owned solar array east of the Mississippi, a 45-MW project in Michigan’s “thumb” region.
The Energy Department is devoting $18 million to help develop ways to integrate solar generation and battery storage in order to overcome the challenge of matching the intermittent production of solar power to market demands.
Seven energy companies have joined to create a national trade association to promote community solar projects, which are financed by subscribers who receive solar energy credits on their bills.
The Nuclear Regulatory Commission approved licenses to build two new reactors at the South Texas Project nuclear plant southwest of Houston, but NRG Energy and its partners have no plans to build them because of competition from cheaper power suppliers.
Utility-scale wind and solar will account for 6% of electric generation in the U.S. in the coming year, according to a report from the Energy Information Administration. Although solar’s share is less than 1%, it represents a 28% increase over 2015.
FERC last week ordered PennEast Pipeline to provide more information on its proposed 110-mile natural gas pipeline that would run from Pennsylvania under the Delaware River and into New Jersey, saying it wants to know more about how the pipeline would affect several nature preserves.
