Company Briefs

Duke Energy has announced plans to buy power produced from methane collected from livestock waste.

Duke has contracted with Carbon Cycle Energy, which will build and own a plant that will generate enough electricity from chicken and swine waste to power about 10,000 homes a year.

The plant will likely be located in eastern North Carolina. The state, which falls just behind Iowa as the country’s largest pork-producing state, requires utilities to produce power from swine and poultry waste. The state’s renewable energy law also requires utilities to procure 12.5% of its power from renewable sources by 2021.

More: Insurance Journal

Black Hills Energy Starts Construction on Tx Line

Black Hills Energy has started construction on a 144-mile, $54 million transmission line that will run from northeast Wyoming to Rapid City, S.D.

The 230-kV Teckla-to-Rapid City project is about a year behind schedule because of delays to get permission from property owners, who held out for higher easement payments. The company also needed permission from the federal government to run the line through the Black Hills National Forest.

More: Rapid City Journal; Black Hills Energy

Atlantic Coast Pipeline Sells 96% Of Capacity, Surveys 90% of Route

The operator of the Atlantic Coast Pipeline, a $5 billion pipeline that will deliver natural gas from Appalachian shale fields to Virginia and North Carolina, has sold 96% of the future pipeline’s capacity and surveyed 90% of the 550-mile route, according to an update from the company.

Dominion Energy President Diane Leopold said 90% of the 2,800 landowners along the route have allowed survey teams on their land and 500 have signed easements. She also said that a Pennsylvania steel mill is set to start manufacturing the pipe in a $400 million contract.

More: The Associated Press

Ex-Austin Energy Chief Confirmed As Seattle City Light’s GM, CEO

The former head of Austin Energy was approved as Seattle City Light’s general manager and CEO, despite criticism over his January remarks that Austin’s utility should be run by an independent board and not the City Council.

The Seattle City Council voted 7-2 to confirm a four-year appointment of Larry Weis to run the city’s electric utility. He will earn $340,000 a year.

Council members made few explicit references to Weis’ time at Austin Energy, but his record was central in the public testimony at his confirmation hearings. His supporters praised him for winning over the union that represents Seattle City Light workers and for his decision to hire a director of environment and sustainability issues.

More: Austin American-Statesman

Lincoln Electric Plan Calls for $453M in Upgrades, Expansions

Lincoln Electric System, the Nebraska public utility serving the state capital region, approved a six-year $453 million capital budget to replace and upgrade infrastructure.

Lincoln Electric, an SPP member that has about 120,000 customers, says it expects to add 9,400 customers, move the overhead service lines for 1,800 customers underground and add 44 MW of new load to its system. Its two most costly projects call for $204 million to update overhead and underground distribution and transmission lines and $152 million for power generation facilities.

Almost $100 million is slated to update power plants to comply with EPA’s Clean Power Plan.

More: Lincoln Journal Star

Two Westar Employees Threatened By Residents When Changing Meters

Two Hutchinson, Kan., residents were arrested in separate incidents for threatening Westar Energy employees who swapped out their old electric meters.

County officials charged a resident who held a Wester employee at gunpoint with aggravated assault and kidnapping. Four days earlier, deputies arrested another Hutchinson resident who threatened bodily harm to a Westar employee who had changed his meter.

More: The Hutchinson News

Duke Energy’s California Deal Expands its Solar Stable

Duke Energy Renewables has purchased a proposed 20-MW solar project in California from EDF Renewable Energy. The project, to be built in San Bernardino County near Barstow, will be called the Longboat Solar Power Project.

The output and the renewable energy credits are being sold to Southern California Edison in a 20-year power purchase agreement.

The project, which is expected to come online by the middle of this year, will bring Duke’s solar stable in California to 130 MW. Duke’s regulated and commercial businesses have invested more than $4 billion in solar and wind generation over the past eight years.

More: Duke Energy

Dynegy Announces Closure Of Wood River Plant in June

Dynegy’s coal-fired Wood River plant in Illinois will be shuttered in June after a MISO study concluded it was no longer needed to ensure reliability in the region.

The company said the plant was unprofitable under MISO’s “poorly designed” capacity market. About 90 jobs will be lost when the plant closes. The plant also pays about $1.6 million in community property taxes.

Dynegy anticipates that cleaning up the West Alton plant’s coal ash ponds will cost $18 million. The plant produced 465 MW from its two units, which went into service in 1954 and 1964.

More: The Telegraph

March 23, 2016

UPDATE: Exelon Closes Pepco Merger Following OK from DC PSC

By Suzanne Herel

Exelon closed its $6.8 billion acquisition of Pepco Holdings Inc. on Wednesday, after the D.C. Public Service Commission approved the merger 2-1 on terms it crafted itself.

Two years in the making, the deal will rank Exelon as the largest utility in the country by number of gas and electricity customers.

Pepco shares gained $5.71 (27%) to $26.95 on the news, while Exelon shares lost 28 cents (-0.8%). Pepco stockholders will receive $27.25/share in the deal. PHI’s common stock was removed from the New York Stock Exchange on Thursday.

Pepco’s three operating companies will retain their local headquarters: Atlantic City Electric in Mays Landing, N.J.; Delmarva Power in Newark, Del.; and Potomac Electric Power Co. in D.C.

D.C. also won additional concessions: Exelon will move the offices of the CFO and the chief strategy officer to the district along with that of Pepco Energy Services, which is now in Arlington, Va. David Velazquez will assume the role of president and CEO of PHI, a post previously held by Joseph Rigby, who is retiring.

“Today, we join together as one company to play a vital role as a leader in our industry and the mid-Atlantic region,” Exelon CEO Chris Crane said in a statement. “We’ve made a number of commitments to customers in all of the Pepco Holdings utilities’ jurisdictions — the district, Maryland, Delaware and New Jersey — and we look forward to getting to work to deliver those benefits to our customers and communities.”

An Exelon spokesman said the D.C. agreement triggers the “most favored nation” clauses in the other states’ contracts, and it will be returning to those state regulators to “true up” benefits.

So far, Exelon has committed $430 million for ratepayer credits, reliability improvements and other investments for customers in Pepco’s service territories.

DC PSC Lifeline

Many had expected the deal to fail, after the most recent proposal by Exelon and Pepco was rejected by all but three of the other settling parties.

The companies on March 7 asked the commission to consider three options: Revisit its rejection of the settlement agreement brokered by the administration of Mayor Muriel Bowser; adopt the revised proposal by Commissioner Joanne Doddy Fort; or accept a third alternative that would give the PSC more latitude in how to spend money from the $72.8 million customer investment fund on rate relief. (See Exelon-Pepco Deal Doubtful as DC Officials Reject Alternatives.)

Fort and Commissioner Willie Phillips voted to approve the second option; Chairwoman Betty Ann Kane dissented.

Fort’s proposal took Bowser’s deal and added changes regarding the use of the CIF, the development of a 5-MW solar generation facility at the Blue Plains Advanced Wastewater Treatment Plant and the role of Pepco in establishing public-purpose microgrids.

The Bowser-brokered deal had earmarked money from the CIF for a handful of D.C. groups, including the Sustainable Energy Trust Fund, the District of Columbia Consumer and Regulatory Affairs Green Building Fund and the Low Income Home Energy Assistance Program.

The PSC’s counteroffer takes those funds, totaling $32.8 million, and places them in an escrow account to pay for projects to modernize the district’s energy system and for energy efficiency and energy conservation initiatives focused on housing for low- and limited-income residents. The PSC would have authority over the funds’ disbursement.

In her dissenting opinion, Kane said that developments in the record since she voted to oppose the Bowser settlement in February “give me even stronger reasons to find that the takeover of the district’s electric distribution company by a multi-faceted, vertically integrated, generation-focused holding company … benefits Pepco and Exelon shareholders but does not provide sustainable benefits to district ratepayers, places Pepco within a structure that is contrary to district law and policy and should be rejected.”

Unlike a rate case, she said, the sale of Pepco can’t be reviewed again. “It is gone forever,” she said. “The stated motive of the sellers is to increase PHI shareholder value. The motive of the buyer is to add regulated revenue to prop up Exelon’s failure to pay dividends to its shareholders. However, the needs of Pepco’s customers and the district are for a safe, reliable, modern electricity delivery distribution system at a just and reasonable cost.”

In their order, Fort and Phillips said Exelon’s first option identified no error of law or fact that would warrant a reconsideration of its rejection of the settlement negotiated by Bowser’s office.

It found the third alternative unacceptable for three reasons: It would allocate a $25.6 million base rate credit solely to residential and apartment customers; there was not enough information to determine the implications of the proposed base rate credits; and the shift of funding to rate credits would come at the expense of projects that would make the grid better able to accommodate distributed energy resources.

In offering the settling parties the retooled agreement, the commission already had judged it to be in the public interest.

Fort and Phillips said their revised settlement ensures that the district receives the $72.8 million CIF, which will be used for rate relief, energy conservation programs and projects to modernize the distribution grid and enable it to accept more distributed resources, “thereby further promoting the district’s sustainability agenda.”

“These are all funds that will not be available to district ratepayers or the district if the merger is not approved,” they said, adding that the changes made to the Bowser settlement “ensure that the district’s market remains a competitive one for suppliers who want to bring more renewable energy resources to our city while still requiring Exelon to invest in 7 MW of new solar in the district and 100 MW of new wind” in PJM.

Disappointment and Surprise

Power DC, a coalition formed against the deal, said, “We are profoundly disappointed and saddened that the D.C. Public Service Commission has ignored the clear opposition to the proposed Exelon-Pepco merger voiced by the district’s elected officials, community and business leaders, and residents.

“By approving the merger, the PSC has exposed our city to decades of higher rates, weakened its own ability to guide our city’s energy future and helped ensure that D.C. will fall behind the rest of the U.S. on clean, efficient energy.”

“I don’t think we’re surprised” at the ruling, said Williams Fields, senior assistant in the Maryland Office of People’s Counsel, which has appealed the Maryland Public Service Commission’s earlier approval of the deal. “It’s been down a long path. We haven’t read the ruling yet. We will have to evaluate on how it impacts Maryland in regards to additional funding from our most-favored-nation status. And, of course, we will have to see how it affects our appeal.”

Montgomery County, Md., Councilman Roger Berliner, who had campaigned against the merger, said in a statement that the merger approval was “deeply disappointing.”

“Its approval now means that Exelon will totally dominate the Maryland market,” he said. “Environmental and consumer interests were needlessly sacrificed. The only winners are Pepco shareholders and Exelon’s bottom line, a bottom line that has been hammered by its huge investment in nuclear power.”

David Bonar, Delaware’s Public Advocate, said he was “pleasantly surprised.”

“I’m glad to see that it is finally resolved. Each jurisdiction has its own idiosyncrasies and partners who have a right to input, and I’m glad they all had an opportunity to add their input,” he said.

“I think the [D.C.] PSC made the right decision. Now, we have to figure out exactly what it means to us in regards to additional funding. It will come out to several millions of dollars. I certainly hope we can give energy users some long-term benefits, like meaningful energy efficiency programs.”

The Apartment and Office Building Association of Metropolitan Washington was the only settling party to file its support of the commission’s revised proposal.

Those opposing it were the National Consumer Law Center, National Housing Trust and National Housing Trust-Enterprise Preservation Corp., the D.C. Office of the People’s Counsel, the Bowser administration and the D.C. Water and Sewer Authority.

They took issue with the PSC’s requirement that $25.6 million of the CIF earmarked for residential rate relief be held in escrow until the next Pepco rate case and then be considered for disbursement, including to nonresidential customers.

“Despite the commission’s perplexing approval of a proposal that OPC and most of the other settling parties rejected, the Office of the People’s Counsel is fully prepared to continue to aggressively advocate for ratepayers and fight to ensure that rates remain affordable for consumers, particularly for our most economically vulnerable residents,” People’s Counsel Sandra Mattavous-Frye said.

The NCLC and the NHT were the only settling parties to voice support for the companies’ third alternative.

“Should option three be rejected, the merger is likely to collapse,” they said. “From the perspective of NCL/NHT, this is contrary to the public interest and particularly contrary to the interests of low-income households in the district.”

The General Services Administration, the largest consumer of electricity in the district, had not signed on to the settlement negotiated by Bowser but had voiced concern that the included rate relief would not be disbursed to non-residential customers. It initially supported the commission’s revised proposal, which addressed that issue, but on March 17 filed comments urging the PSC to reject Exelon’s filing.

Exelon has spent an estimated $259 million over the past two years trying to capture Pepco’s $7 billion rate base.

Ted Caddell contributed to this article.

March 22, 2016

DC PSC Set to Decide Exelon-PHI Merger Fate Wednesday

[SEE UPDATE: DC PSC OKs Exelon-Pepco Deal.)

By Suzanne Herel

The D.C. Public Service Commission is poised to decide Wednesday the fate of the controversial proposed merger of Exelon and Pepco Holdings Inc.

dc psc, exelon, pepco, exelon-pepco merger — DC PSC Commissioners at the bench *© RTO Insider*

The $6.8 billion deal looks in doubt, as the most recent proposal by Exelon and PHI was rejected by all but three of the other settling parties.

The companies on March 7 asked the commission to consider three options: Revisit its rejection of the settlement agreement brokered by the administration of Mayor Muriel Bowser; adopt the revised proposal offered by the commission; or accept a third alternative that would include no additional money for a customer investment fund, but would give the PSC more latitude in how to spend it regarding customer rate relief. (See Exelon-Pepco Deal Doubtful as DC Officials Reject Alternatives.)

It asked the commission to rule by April 7.

The Apartment and Office Building Association of Metropolitan Washington was the only settling party to file its support of the commission’s revised proposal.

Those opposing it were the National Consumer Law Center, National Housing Trust and National Housing Trust-Enterprise Preservation Corp., the Office of People’s Counsel, D.C. government and the D.C. Water and Sewer Authority.

They took issue with the PSC’s requirement that $25.6 million of the roughly $78 million customer investment fund earmarked for residential rate relief be held in escrow until the next Pepco rate case and then be considered for disbursement, including to nonresidential customers.

The NCLC/NHT were the only settling parties to voice support for the companies’ third alternative.

“Should option three be rejected, the merger is likely to collapse,” they said. “From the perspective of NCL/NHT, this is contrary to the public interest, and particularly contrary to the interests of low-income households in the district.”

The General Services Administration, the largest consumer of electricity in the district, had not signed on to the settlement negotiated by D.C. government, but had voiced concern that the included rate relief would not be disbursed to non-residential customers. It initially supported the commission’s revised proposal, which addressed that issue, but on March 17 filed comments urging the PSC to reject Exelon’s filing.

The first option proposed by the companies should be rejected because it did not include grounds that the commission’s rejection was “unlawful or erroneous.” The second should be dismissed because it was not approved by all of the settling parties, as the PSC required. The third should be refused as either a petition for reconsideration or a new settlement agreement that would be subject to normal commission proceedings, it said.

Chris Crane testifying on the exelon-pepco merger at the DC PSC — CEO Chris Crane *Source: DC PSC*

Exelon has spent an estimated $259 million over the past two years trying to capture Pepco’s $7 billion rate base.

CEO Chris Crane said in a Feb. 3 earnings call that the company was prepared to immediately begin buying back the 57.5 million shares it issued for the $6.8 billion deal if the merger fell through.

The uncertainty of the merger has taken a toll on Pepco’s stock. In late afternoon trading, it was down 52 cents (2.37%) at $21.45. Exelon shares have remained largely unaffected. In late afternoon trading they stood up 30 cents (0.85%) at $35.18.

March 21, 2016

Market Policies, Emissions Goals on Collision Course in New England

By William Opalka

BOSTON — ISO-NE market rules favoring natural gas are on a collision course with state and federal environmental mandates, speakers at the EUCI US/Canada Cross-Border Power Summit said Tuesday.

Left to itself, renewable energy advocates said, the market would dictate a shift to natural gas, and only natural gas, ignoring the impact on greenhouse gas emissions.

Backers of gas generation countered that renewables are benefiting from government-backed subsidies and long-term contracts that threaten to reintroduce government-mandated integrated resource planning.

Dan Dolan of NEPGA at EUCI Summit discussing renewable energy, natural gas — Dolan *© RTO Insider*

Dan Dolan, president of the New England Power Generators Association, told the conference that state policies are giving renewables undue advantage and undermining conventional generators’ investments in the market.

He cited state-backed long-term contracts that could introduce more than 2,000 MW of Canadian hydropower into the region. “You can’t add that much stuff onto the plate without some of the soup getting spilled over the side,” Dolan said.

In the last two Forward Capacity Auctions conducted by ISO-NE, about 3,200 MW of new gas-fired generation has successfully bid into the market, he said. “Of all those megawatts of cleared resources, not a single one of those has a state-backed long-term contract or other subsidy,” Dolan said.

Francis Pullaro at EUCI summit discussing renewable energy, natural gas — Pullaro *© RTO Insider*

Francis Pullaro, executive director of RENEW Northeast, which represents renewable energy developers and environmental organizations, said current market rules skew toward natural gas and disadvantage clean energy resources. Natural gas “resources are going to be built over the next couple years with generous capacity payments” that make financing easier to obtain, he said.

Under the FCAs run by ISO-NE, resources are able to lock in prices for seven years. Renewables, Pullaro pointed out, have little capacity value and are only able to obtain financing through long-term contracts, which states have required from the electric distribution companies.

“We really can’t add any more gas to the system than what is already expected to come onto the system over the next few years if we are going to meet our greenhouse gas reduction laws,” he said.

Primary among them is the Massachusetts Global Warming Solutions Act, which requires a 25% reduction in carbon emissions from 1990 levels by 2020. Several New England states have followed suit with similar emission-reduction goals.

Janet Besser at EUCI summit discussing renewable energy, natural gas — Besser *© RTO Insider*

To meet its target, Massachusetts Gov. Charlie Baker has proposed a bill, S. 1965, that would allow electric distribution companies to enter into long-term contracts for large hydropower resources and offshore wind.

Janet Besser, vice president of policy and government affairs for the Northeast Clean Energy Council, a trade group for clean energy businesses, said the legislation’s support of offshore wind is “a critical component of the bill.” Wind, combined with hydro resources, could provide firm capacity, especially with a transmission buildout to connect remotely sited resources, she said.

Bartlet at EUCI, discussing renewable energy, natural gas — Bartlett *© RTO Insider*

“It’s an overarching policy goal and it is also a goal of customers. They want resources something other than gas … they are not resources being delivered by the market alone.”

The battle for generation market share is unlikely to end any time soon, as the region also faces the prospect that almost 6,000 MW of coal and oil-fired generation that is at least 40 years old will retire in the next few years.

That, observed Ned Bartlett, undersecretary of energy and environmental affairs for Massachusetts, is “enough power to supply Maine, New Hampshire, Vermont and Rhode Island combined.”

March 21, 2016

FERC Transmission Metrics Report IDs Potential Underinvestment

By Rich Heidorn Jr.

All but one of the organized markets under FERC jurisdiction have regions that show signs of transmission underinvestment, according to the commission’s first transmission metrics report.

FERC’s Office of Energy Policy and Innovation (OEPI) was tasked last year with collecting data to evaluate the impact of Order 1000 and other commission policies intended to encourage competition and infrastructure growth. The research also sought to determine whether regions have “appropriate levels” of transmission infrastructure. (See “Transmission Investment Metrics,” FERC Briefs.)

The staff report identified 13 areas — including every ISO and RTO under FERC jurisdiction except ISO-NE — in which there were persistent high or low prices, suggesting a lack of transmission was preventing load pockets from accessing cheaper generation. Some of the areas — including the Baltimore area and Delmarva Peninsula in PJM, North-Central MISO, the Chicago area, the Upper Peninsula of Michigan and Northern New York — have shown price separations for nine or 10 years.

The report also confirmed that Order 1000 has unleashed competition, with nonincumbent transmission developers submitting almost half of the proposals received by CAISO and PJM from 2013 through 2015. (Data was not available from other regions such as MISO and SPP, which are just beginning to open competitive windows.)

“One hope in issuing this report is that people will look at the assumptions we’ve made and provide feedback and perhaps ideas for additional metrics,” OEPI staffer Rahim Amerkhail said at the conclusion of a presentation to the commissioners at Thursday’s open meeting.

Below are the metrics and key conclusions:

Percentage of Nonincumbent Transmission Project Bids

Nonincumbents submitted 48% of all competitive transmission project proposals in CAISO’s and PJM’s regional planning processes from 2013 to 2015 (excluding a PJM window that closed last September, for which the RTO had not posted proposals). Nonincumbent proposals accounted for the majority of proposals in all three years in CAISO. In PJM, nonincumbents submitted the majority of proposals in 2013 and 2015, but less than 40% of proposals in 2014.

Staff identified incumbents as those making proposals in their own retail distribution service territory.

Load-Weighted Curtailment Frequency

Staff assumed that persistent congestion in an area suggests there is not enough available transfer capability to deliver power from the cheapest resources.

For RTO and ISO markets, staff looked at LMPs. For non-RTO/ISO market regions in the Eastern Interconnection, staff used NERC transmission loading relief (TLR) data. (Such data was not available for the Western Interconnection, which manages unscheduled flows with schedule curtailments and controllable devices such as phase shifting transformers.) Staff normalized the TLR data based on the region’s retail load.

The data found that SPP, MISO and the Tennessee Valley Authority had the highest levels of load-weighted TLRs.

Although MISO’s and SPP’s markets optimize dispatch based on congestion, reducing their internal use of TLRs, they use the procedure to manage unscheduled loop flows originating outside their footprints. “Both MISO and SPP have extensive borders with non-organized market areas, which may help explain their continuing use of TLRs,” staff said.

The data showed SPP’s TLR rate dropped after the RTO launched its day-ahead market in March 2014.

RTO/ISO Price Differential

This metric shows how long RTO/ISO market nodal price differentials have occurred persistently.

Staff looked at real-time prices at each load and generator point — focusing on the 95th and fifth percentiles of prices rather than maximum or minimum prices — then calculated market-wide average highs and lows to identify locations whose high or low prices were at least one standard deviation from the averages.

Staff found relatively high or low real-time LMPs occurred at 1,986 generator or load points from 2012 through 2014. Thirteen areas had differentials spanning at least three years.

Load-Weighted Transmission Investment

A third set of metrics, which compared transmission investment to load and project sizes, was designed to provide a longitudinal analysis comparing values before and after FERC policy changes took place.

Load-weighted transmission investment averaged more than $2/MWh of retail load over all regions from 2008 to 2014. The highest average investment was in the Texas Regional Entity, at more than $4/MWh across all years, reflecting the $5.7 billion spent in the state’s Competitive Renewable Energy Zone (CREZ), an initiative to alleviate congestion and integrate wind generation.

The smallest load-weighted investments were in the SERC Reliability Corp. and Florida Reliability Coordinating Council regions in the Southeast.

A related metric, load-weighted circuit-miles added, produced similar results.

Circuit-Miles per Million Dollars of Investment

The Midwest Reliability Organization added 1.7 circuit-miles of transmission per million dollars invested, the highest of any region, according to the report. PJM’s reliability region, Reliability First Corp., had the most expensive transmission with less than one circuit mile per $1 million spent. The average was 1.1 miles per $1 million.

The differences “may be due to a range of factors, including terrain, population density, and state policy choices, among others,” staff said.

March 21, 2016

Company Briefs

TransCanada, spurned in its attempts to push through the Keystone XL Pipeline last year, announced it will buy Columbia Pipeline Group for $13 billion, including the assumption of $2.8 billion in debt. The deal will give it access to the Appalachian shale plays.

“The acquisition represents a rare opportunity to invest in an extensive, competitively positioned, growing network of regulated natural gas pipeline and storage assets in the Marcellus and Utica shale gas regions,” TransCanada CEO Russ Girling said. Columbia Pipeline has 15,000 miles of pipelines, as well as underground storage and processing facilities.

TransCanada, which just last month bought the 778-MW Ironwood natural gas-fired generating station in Lebanon, Pa., said it will sell off some of its other generating assets in the Northeast to finance the Columbia deal, including Ironwood. Among its plants are the 2,480-MW Ravenswood Generating Facility in Queens, N.Y., and the 560-MW Ocean State Power station in Rhode Island.

More: TransCanada; Bloomberg Business

AEP’s Pablo Vegas Leaving for Columbia Gas

AEP Ohio President Pablo Vegas, who has been the face of the company during its ongoing battle to secure guaranteed rates for some of its aging generating plants, is leaving the company to run Columbia Gas.

Columbia Gas oversees natural gas transmission and distribution in Ohio, Kentucky, Maryland, Massachusetts, Pennsylvania and Virginia. Vegas, 42, was also named executive vice president of Columbia parent NiSource.

Vegas has been with American Electric Power since 2005. He will join Columbia Gas in May, by which time Ohio regulators are expected to decide on AEP’s proposed power purchase agreements.

More: Columbus Business First

Duke’s Gates Going to Calpine, Repko Assuming His Position

Duke Energy’s Charlie Gates is leaving the company to become executive vice president of power operations for Calpine. Gates had overseen all non-nuclear generation assets at Duke, a fleet of about 42 GW. Gates is to oversee Calpine’s fleet of 84 power plants with a capacity of about 27 GW.

Gates will be replaced at Duke by Regis Repko, currently senior vice president of nuclear governance, projects and engineering. Repko will assume the title of chief fossil and hydro officer, in charge of the company’s coal, natural gas and hydro units in six states.

Repko has been with Duke since 1985.

More: Charlotte Business Journal

Coal, Alternative Energy Deal with Money Troubles

Two energy companies from opposite ends of the spectrum — coal producer Peabody Energy and alternative energy developer SunEdison — are reporting financial woes.

Peabody reported to the U.S. Securities and Exchange Commission that it probably won’t be in compliance with its financial requirements by the end of the month, and it might have to file for Chapter 11 bankruptcy protection.

SunEdison said problems in its accounting processes led to a delay in its annual stockholders report. It was also dealt a blow this month when it could not secure the financing necessary to acquire rooftop solar company Vivint.

More: USA TODAY

Alevo Sites Energy Storage System in Del.

Energy storage company Alevo is locating an 8-MW battery storage system in a retired oil-fired generator building in Lewes, Del. The grid-linked system, which is capable of delivering 4 MWh, will be the largest of its kind in the state.

The project, called GridBank, is the first for the Concord, N.C.-based company. The company said it plans to deploy more GridBanks in PJM this year under an agreement with Customized Energy Solutions.

Alevo will be able to sell ancillary power into the PJM regulation market while also providing the Lewes Public Works Department with the ability to shave peak demand for its customers, the company said.

More: Alevo; Charlotte Business Journal

Investors Sweeten the Pot In Cleco Acquisition Bid

Louisiana utility Cleco would give a credit of $370 for the average residential and small-business customer, amounting to a free month of electricity this summer, under a proposal to sell the company for $4.9 billion to a consortium of foreign investors. Cleco President Darren J. Olagues said the credit would be paid within 30 days of the closing of the sale.

The state Public Service Commission last month refused to allow investors to purchase the 80-year-old utility that serves about 286,000 customers in southern Louisiana. The investors have requested a rehearing, which the commission will consider this week.

The Cleco coalition, led by Macquarie Infrastructure and Real Assets, and which includes British Columbia Investment Management Corp., has committed to paying $101 million in upfront rate credits.

More: The Advocate

Sharyland Proposes Tx Upgrade To Meet Wind Energy Demand

Sharyland Utilities has filed a request with the Public Utility Commission of Texas for a $77.4 million transmission line upgrade in the Texas Panhandle to accommodate the growth of wind energy in the region.

The project would add a second set of high-voltage lines on 166 miles of transmission infrastructure that Sharyland completed about three years ago. A study by ERCOT, which runs 90% of the Texas grid but not the Panhandle, estimates the area’s wind capacity is 4,300 MW and is growing.

“Given the dramatic and continued expansion of wind generation in the region, Sharyland should proceed with installation of the second circuit,” PUCT Commissioner Kenneth Anderson wrote in a September memo supporting the move.

More: Amarillo Globe-News

Nebraska’s Largest Solar Farm Opens for Business

Nebraska’s largest solar array is now in business following a March 14 ribbon cutting near Callaway in Custer County. Innovative Solar developed the 600-kW project.

The project was partially funded by a U.S. Department of Agriculture renewable energy grant. Custer Public Power District has agreed to buy the solar farm’s power output.

More: North Platte Telegraph

Peabody Energy Selling Share Of Prairie State Energy Campus

Peabody Energy, fighting to stay out of bankruptcy, is selling its 5.06% share of the Prairie State Energy Campus in Illinois to Wabash Valley Power Association for $57 million. Its original investment in the troubled power plant was $247 million.

The coal-fired plant endured cost overruns and construction delays and is struggling to compete on the open wholesale energy market. The remaining shareholders, mostly Illinois cities such as Batavia and Geneva that own shares through their membership with the Northern Illinois Municipal Power Agency, should not be affected by Peabody’s sale of its shares, a Peabody spokesperson said.

An industry observer, Sandy Buchanan, executive director of the Institute for Energy Economics and Financial Analysis, said municipal shareholders will be left with a large amount of debt that will be a burden on their ratepayers. “All these communities were promised that the cost of power from Prairie State was less than market [price], and the reverse has happened,” Buchanan said.

More: Kane County Chronicle

Report: Aqua America Made Abortive $11B Bid for ITC

Water utility Aqua America apparently made an unsuccessful bid for transmission owner ITC Holdings before the company agreed to be acquired last month by Fortis, according to The Philadelphia Inquirer. The Inquirer quoted from a Fortis merger statement that said “a director of ITC affiliated with Party G, a U.S. publicly traded company, informed [ITC] that Party G might be interested in exploring a potential merger” at a price of about $11 billion.

The only two directors of ITC “affiliated” with public companies, according to the Inquirer, are Aqua CEO Christopher Franklin and Lee Stewart, who is also on the board of a New Jersey plastics maker called AEP Inc. (no connection to American Electric Power). A Wall Street analyst identified Aqua America and Warren Buffett’s Berkshire Hathaway as potential buyers of ITC in a report to investors.

If successful, the Bryn Mawr, Pa.-based company, which runs water and sewer companies in eight states, would have been offering almost twice its own $6.4 billion stock market value. ITC chose instead to be acquired by Fortis, which offered $11.3 billion. Aqua America declined to comment on the report.

More: The Philadelphia Inquirer

March 21, 2016

Modeling Shows Need for Higher Wind Assumptions

By Amanda Durish Cook

The increase in wind generation under the Clean Power Plan would likely exceed MISO’s previous assumptions and require creation of new renewable generation zones, according to a new analysis from the RTO.

MISO’s midterm CPP analysis, presented to the Planning Advisory Committee last week, also quantified the most economic levels of coal retirements under the EPA rule, showing that the cheapest path to full implementation would require the retirement of 16 to 21 GW.

The analysis showed that MISO’s Regional Generation Outlet Study (RGOS) is in need of expansion, said MISO Senior Policy Studies Engineer Jordan Bakke. The 2009 study sought to help states meet their renewable portfolio standards by identifying regions with optimal combinations of wind conditions and distances to load as well as suggesting potential transmission projects to accomplish the goals.

Assumptions Overtaken

The study produced the RGOS zones MISO uses today, with assumptions initially meant to inform decisions until 2026. While actual and queued wind siting has been consistent with those assumptions since 2011, the RTO expects wind installations to begin exceeding projections because the CPP and falling prices mean renewable penetration will exceed levels needed to meet the state renewable mandates on which the earlier study was based.

MISO says the anticipated growth warrants adjustments to the MISO Transmission Expansion Plan renewable siting methodology, as well as adding solar zones into study assumptions.

Bakke said an uptick in renewables is imminent. “In light of the [Supreme Court] stay, the timeline for the CPP is unclear, but in general we’re studying carbon reductions,” he said. “The CPP is only one of many things that are driving carbon reductions.”

To assist its analysis, MISO commissioned renewable planning firm Vibrant Clean Energy (VCE). The company modeled three scenarios: a 30% cut in carbon emissions from 2005 levels by 2030; a 50% emission reduction by 2036; and an 80% cut by 2050.

Among the study’s findings:

MISO’s Zone 1 (Minnesota, western Wisconsin and MISO’s stretch of the Dakotas) is ripe for large amounts of potential wind export capacity by 2050. Zone 1’s wind-rich locations make economic sense for extensive wind build-out and transmission development, VCE concluded in the study, which used an assumed $700/MW-mile transmission cost.
The Great Lakes region could experience a spike in wind production if more transmission was built in that region.
With expanded transmission and the elimination of coal, the MISO grid could handle 217 GW of installed wind generation and 125 GW of solar and generate 861,000 GWh of renewable power by 2050. (MISO’s all-time wind peak is 13.1 GW, set on Feb. 18.)

Wind has a higher capacity factor than solar in MISO’s footprint, making it a more economic option. Bakke noted the VCE study did not include assumptions about distributed generation or energy storage. He said a more complete picture of the study would be presented at MTEP workshops on March 30 and April 28.

Bakke added that MISO’s long-term CPP analysis would deal with the specifics of transmission overlay on a “bus to bus” level. He said MISO hopes to have a new siting methodology finalized with updated wind zones, new solar zones and ozone non-attainment areas by the July PAC meeting.

‘Sweet Spot’ for Coal Retirements

MISO’s midterm analysis also showed that extensive coal retirements would need to accompany wind’s expansion in order to cost-effectively meet CPP standards.

“We’re not going to try to build our way into compliance by having a very high reserve margin,” Bakke said. “What the system has to do to comply is shift away from coal.”

The analysis set out three scenarios for retiring coal under the CPP through 2034, with the most economic levels of retirements varying based on carbon emissions reductions:

Under the “final CPP” scenario unaltered by current legal challenges (a 34% reduction in CO₂ emissions from 2005 levels), 16 to 21 GW of coal retirements would be most economic.
Accelerated CPP compliance (a 43% decrease in emissions) results in 24 to 30 GW of coal retirements.
Partial CPP compliance (a 17% cut in emissions) results in retirement of 8 to 11 GW of coal.

‘Bathtub Curve’

In every scenario, total costs of compliance over the 19-year period exceeded $237 billion. But costs could be considerably higher if too much, or too little, coal retires.

In a scenario with no coal retirements, Bakke explained, MISO would be forced to redispatch from coal to older, more expensive gas plants in order to comply with CPP mandates. Retirements of the least efficient coal units would lead to replacement with newer, more efficient gas plants, driving down production costs.

Still, system costs would amplify if coal retired beyond rates needed to comply with the CPP, as more expensive natural gas and renewables drive costs higher, resulting in what Bakke referred to as a “bathtub curve” on modeling graphs. Bakke pointed out that high costs from too many retirements were unlikely, as generators would not be inclined to over-comply with any final version of the CPP rule.

“The system naturally doesn’t want to retire this much coal,” Bakke said.

March 21, 2016

Constitution Pipeline Delayed Nearly a Year

By William Opalka

Conceding that much of the 2016 construction season has been lost due to regulatory delays, the developers of the Constitution Pipeline say the project will be delayed by nearly a year (CP13-499).

The pipeline, which is intended to deliver shale gas from Pennsylvania into the New York and New England markets, is now projected to begin service in the second half of 2017. The developers had proposed operation of the 124-mile pipeline in the fourth quarter of this year.

FERC did not act on the developer’s request to cut trees in New York before March 31, so that window has closed. (See Constitution Again Seeks Tree-Felling Permission in NY.) Constitution is required to cut trees between Nov. 1 and March 31 to comply with U.S. Fish and Wildlife Service recommendations to mitigate impacts on migratory birds and the northern long-eared bat. FERC did not grant permission in New York but did allow those operations in Pennsylvania, which have been completed.

“The March 2, 2016, target date for receipt of written authorization has passed and, as a consequence, Constitution will not be able to complete the required tree felling within the deadline established by the United States Fish and Wildlife Service,” the company wrote in a letter to FERC. “The renewed request for written authorization to conduct tree felling set out in the Feb. 25 letter, accordingly, is now moot and no longer needed. Constitution will file a new request for the necessary authorization at the appropriate time.”

New York Attorney General Eric Schneiderman had opposed the operation, saying FERC should not allow tree felling without a Section 401 permit under the federal Clean Water Act, to be issued by state environmental officials.

Constitution spokesman Chris Stockton said the New York Department of Environmental Conservation has until April 29 to render its decision. He added that construction in Pennsylvania will continue and some activities in New York away from stream crossings would proceed.

March 21, 2016

FERC to Revisit Transmission Policies

By Rich Heidorn Jr.

FERC will hold a two-day technical conference to review its transmission policies, an initiative that may result in refinements to its Order 1000 rules on competition and its 2006 order offering incentives to developers.

Chairman Norman Bay announced Thursday that the commissioners will lead a technical conference on competitive transmission development processes June 27-28. Bay said the conference will look at issues including the use of cost containment provisions and the relationship of FERC incentives to competitive development (AD16-18).

Bay made the announcement after a staff presentation on the results of a data-gathering initiative to measure the effectiveness of Order 1000 and other transmission initiatives. (See related story, FERC Transmission Metrics Report IDs Potential Underinvestment.)

The technical conference also makes good on a promise the commission made in an order Thursday rejecting ITC Grid Development’s request that FERC bar transmission rate reductions in Order 1000 solicitations (EL15-86).

ITC’s petition for a declaratory order asked that the commission rule that winning bids subject to binding revenue requirements be deemed just and reasonable and treated similar to a “black box settlement.” It also sought a FERC ruling that such bids are entitled to Mobile-Sierra protection, meaning they cannot be changed as a result of a complaint unless it harms the public interest.

ITC said it plans to compete for transmission projects in SPP, MISO and potentially other areas with bids that include a projected annual transmission revenue requirement. It said the protection it sought would function similar to an abandoned plant incentive, which ensures developers recover their costs when projects are canceled due to events beyond their control.

‘Asymmetrical Risk’

Absent such protection, ITC said, developers will face an “asymmetrical risk.” The company said both MISO and SPP are requiring binding cost caps that leave developers liable for cost overruns. But if the developer is able to reduce costs, its savings could be negated as a result of a Federal Power Act Section 206 complaint.

The company’s petition attracted dozens of interventions from incumbent transmission owners, regulators, trade groups and industrial electric customers.

FERC sided with commenters who said ITC’s request should be considered as part of a broader rulemaking.

“ITC’s petition highlights important policy issues related to the potential benefits of cost containment proposals in the context of competitive transmission development. However, a petition for declaratory order is not the appropriate means for addressing these issues,” the commission ruled.

NextEra Request

The commission said the technical conference will be the forum for discussing the issues raised by ITC and by NextEra Energy Transmission West in a request it filed last year seeking transmission rate incentives for projects in CAISO. The commission responded to NextEra’s request in a January order that granted its request in part and set the company’s base return on equity request for settlement judge procedures (ER15-2239).

That order also promised a technical conference, which it said would consider how risks associated with cost containment proposals relate to the “first expectation” set forth in its 2012 policy statement, Promoting Transmission Investment Through Pricing Reform (RM11-26).

“The commission explained in the policy statement that an applicant seeking an incentive ROE would need to demonstrate that the proposed project faces risks and challenges that are not either already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives.”

The order also said the conference would look at how risks assumed by developers submitting cost-capped bids relate to in the policy statement’s expectation that an applicant seeking an ROE incentive based on a project’s risks and challenges “demonstrate that it is taking appropriate steps and using appropriate mechanisms to minimize its risks during project development.”

Anecdotal Evidence, Rising Rates

Commissioner Tony Clark said stakeholders have told him “‘In this particular region we’re seeing this and we think it works well and we’re seeing this in other regions and we don’t think it works quite as well.’ So it’s just time to do an analysis of that in less an anecdotal way and more of a systematic way to see if there’s lessons that have been learned.”

Commissioner Colette Honorable said she also has been hearing from stakeholders about ways to improve transmission planning and cost allocation processes. “Goodness knows we have work to do there,” she said, citing interregional planning as “the tougher [nut] to crack.”

The failure of grid operators to agree on any interregional transmission projects has been a disappointment to developers and wind power advocates.

Honorable also called for the commission to balance the need for additional transmission against costs. “When I first began as [an Arkansas Public Service] commissioner in ’07, I think transmission costs were on average no more than 10% of a consumer’s bill,” she said. “I’m hearing now it’s as much as 20% in some areas.”

March 21, 2016

SPP Wins OK for Late Billing Changes

FERC last week granted SPP’s request to resettle past bills outside of the 365-day limit in its Tariff (ER16-636).

SPP asked to waive the time limit, citing software-design flaws and the commission’s timing in accepting previous Tariff changes. FERC said it granted SPP’s request because “the underlying error was made in good faith” and the fix caused no “undesirable consequences.”

The problem dates back to the launch of the RTO’s Integrated Marketplace in March 2014. SPP said between March 1 and May 2014, software and/or input errors forced it to recalculate LMPs and market clearing prices in the real-time balancing market. The RTO said a second software error affected settlements for 15 operating days in 2014, and a third error resulted in it undercharging market participants for reliability unit commitment make-whole payment distribution charges.

SPP said some of the errors were discovered more than a year after the operating day. The RTO said software developers could not correct the design flaws in time to adjust all the required market settlements within the 365-day window prescribed in Tariff Attachment AE.

All told, the resettlements represent more than $53,000 in underpayments or overpayments.

– Tom Kleckner