Page 1444 – RTO Insider

December 22, 2015

MISO Unveils Queue Rule Transition as Wind Advocates Seek Delay

By Amanda Durish Cook

CARMEL, Ind. — MISO has settled on a transition plan for its new interconnection queue rules and intends to file Tariff changes with FERC by the end of the year, despite wind advocates’ complaints that the process has been rushed.

MISO said it plans to stagger implementation, “processing some projects under the existing rules and transitioning certain projects to a portion of the new process.”

Between Feb. 20 and May 20, MISO plans to finalize existing generation interconnection agreements and facilities studies, with GIAs completed for the latter by late August. These GIAs will be at the top of the queue for all study cycles to follow.

The RTO will also finish all incomplete system impact studies by Aug. 27 and give the owners of those projects an option by early September to either move into phase three of definitive planning under the existing rules, paying an M4 milestone, or enter phase one of definitive planning under the revamped queue without having to pay another M2 milestone fee.

Projects that haven’t yet entered into a system impact study by Feb. 20 will be rolled into the reformed queue.

Vikram Godbole, senior manager of MISO’s generator interconnection planning group, said interconnection customers with pending GIAs as of Feb. 20 will be targeted first to complete negotiations.

“It’s a tall order, I realize that,” Godbole said of the dates outlined in the transition plan.

Throughout the process, staff representing Minnesota-based Wind on the Wires have complained that the adoption of the new queue timeline and rules has been rushed. The wind advocacy group says that costs remain too high under the new rules and wants MISO to eliminate the M4 milestone payment and create a cost cap on network upgrades. It has asked that MISO delay implementation of the rules until it reaches an agreement with the group.

Godbole said that the new queue will be implemented despite any future required Tariff changes to the interconnection process that may arise due to resource adequacy Tariff revisions. He said those will be handled in the future “as necessary.”

He added, “Any aspects from a technical perspective will be done at the [Business Practices Manuals] level. We’ll take those on next year.”

MISO will use the M2, M3 and M4 milestone payments surrendered by owners of non-viable projects to compensate other interconnection projects that were negatively impacted by the withdrawals.

Godbole said the new queue rules are intended to reduce the number of customers who keep non-viable projects in the queue until the “tail-end.”

“We’re doing this for interconnection customers,” Godbole said. “We want to make sure that people who come into the process ready are rewarded.”

In early December, stakeholders said interconnection customers should be able to use their M2, M3 and M4 payments to fund their initial milestone payment in the 30 days following completion of a generator interconnection agreement. Although MISO denied the request, the grid operator offered a willingness to discuss the option with stakeholders and, depending on the outcome, file Tariff revisions sometime in 2016.

During the last round of comments on Dec. 7, stakeholders requested the addition of a third penalty-free withdrawal option if estimated costs increase more than 25% between MISO’s system impact study and facilities study. Godbole said that MISO evaluated the merits of a third off-ramp “intensely” but ultimately determined not to provide it because the proposed queue reform is more economical for interconnection customers than the queue currently in place.

Stakeholders also criticized the M3 and M4 milestone floors of $2,000/MW, arguing that the cost never actually dips to $2,000, so the threshold is “illusory.” MISO declined to raise the floor, saying that the limit was FERC-approved and costs could come down in the future. (See MISO Cuts Queue Admission, Adds ‘Off-Ramps’.)

December 22, 2015

MISO Planning Advisory Committee Briefs

CARMEL, Ind. — The review process for MISO’s Business Practices Manuals has been rewritten to clarify the RTO’s obligations and the Planning Advisory Committee’s role.

The revised language directs MISO to identify “outstanding or unresolved issues” when presenting BPM changes to the PAC, adds “timing concerns” to the process and allows the committee to modify changes to manuals brought forward by subgroups, instead of delegating work back to the original subgroup.

Matthew Tackett, a MISO principal adviser, said the goal was to make the steps of the evaluation clearer. The language rework was first brought up at the Nov. 11 PAC meeting.

MISO is asking for stakeholder comments on the edits through Jan. 22. A finalized version of the language will return to the February PAC meeting for approval.

MISO Adds Conditions for Stakeholder Notification and Advice into Expedited Review Process

MISO reviewed with the PAC proposed revisions to BPM 020 governing the expedited review process, which will replace out-of-cycle reviews.

The revisions require MISO to “promptly” notify stakeholders of expedited projects whose voltage, cost and other criteria would otherwise make it subject to competitive bidding under FERC Order 1000. Projects will be ineligible for expedited status if they meet criteria for market efficiency projects and “are not needed to meet the obligations or requirements of the transmission owner.”

Tackett said the size criteria was instituted so stakeholders wouldn’t be notified too many times in a cycle. “I use the analogy of junk mail. You get too many and you start saying ‘Oh I don’t care about that,’ and you miss the $300 million one,” Tackett said.

Chris Plante with Wisconsin Public Service Corp. said that an “open, collaborative process requires that stakeholders know what’s going on.” Plante pointed out that in the past there’s been “at least one” large out-of-cycle project that didn’t continue in the process once stakeholders had the opportunity to weigh in on its usefulness and urgency.

The changes also require MISO staff to consider the PAC’s input in deciding whether to bring the requested project to the attention of the Board of Directors’ System Planning Committee. “Stakeholders may also provide advice relative to the project to the SPC and/or the board in accordance with the protocols of the Advisory Committee,” the manual says.

“We realize this is a very controversial subject. There’s a time to move on and then there’s consensus, and this may be an example of that,” said Tackett, explaining that MISO is allowing further rounds of discussion.

Final Review on Minimum Project Requirements for Competitive Bidding Pushed Back

MISO asked for another round of comments by Jan. 12 on BPM 029, which defines the requirements of transmission projects eligible for competitive bidding.

Tackett said he didn’t think any conflicts would arise between the manual and the competitive bidding process for the Duff-Coleman project. He said the manual would be a living document and subject to further improvements but couldn’t foresee a needed change over the next six months as bids are prepared.

“It deals with topics where there’s lots of different opinions on how to do things,” Tackett commented. “I like to call it ‘version one final.’”

Nearly Half of All MTEP Projects in Service, MISO Reports

Almost half of all projects included in the MISO Transmission Expansion Plan were in-service as of the third quarter of 2015, Senior Transmission Planning Engineer Matt Ellis told the PAC in the bi-annual MTEP status update.

MISO reported that 47% of the $22.5 billion in MTEP projects given the go-ahead since 2003 are in service, while 39% remain in the planning stages. Another 8% are currently under construction and the remaining 7% have been withdrawn. The latest numbers do not include projects in the recently approved MTEP15. (See MISO Board of Directors Briefs.)

Ellis said the latest cost estimates on economic-based projects were positive, with benefit-to-cost ratios above projections. He also said almost all of MISO’s baseline reliability projects are on schedule.

“MISO’s post-approval role is to provide transparency,” Ellis said of the update. He added that MISO’s transparency goal will become more challenging with the introduction of competitive bidding, since transmission cost estimates submitted in the developer selection process are considered commercially sensitive information.

Loss of Load Working Group to be Absorbed Under Redesign

PAC Chairman Bob McKee said the committee is “getting off light” compared to assignments doled out to other MISO groups under the stakeholder redesign, with only a short to-do list. The PAC will absorb the Loss of Load Expectation Working Group into a broader, yet-to-be-formed Resource Adequacy Committee. There is no timeline yet on when the move will happen.

“It’s was a nice interactive approach between the stakeholders and MISO,” McKee said of the redesign.

— Amanda Durish Cook

December 22, 2015

Manitoba-Minnesota Tx Line Granted Rate Incentives

By Amanda Durish Cook

ALLETE won FERC approval last week for rate incentives on the Great Northern Transmission Line between Manitoba and Minnesota.

FERC’s order allows ALLETE to recover 100% of construction work in progress (CWIP) for the 220-mile, 500-kV line. It also will recover all of its “prudently incurred” costs if the project is abandoned or canceled due to factors beyond ALLETE’s control (ER16-118).

“Including 100% CWIP recovery in the rate base will provide ALLETE with steady cash flow during the construction period, protecting ALLETE’s financial metrics and relieving downward pressure on its credit rating,” FERC explained.

Great-Northern-Transmission-Line-(Minnesota-Power)-web — (Click to zoom)

The commission said that using CWIP recovery as opposed to employing allowance for funds used during construction (AFUDC) would help “insulate” ALLETE’s ratepayers against sticker shock. FERC also said ALLETE’s proposed accounting and tracking procedures are “sufficient” to ensure that customers won’t be double-charged under the recovery and AFUDC.

According to FERC, ALLETE claims the Great Northern project “presents substantial physical risks and challenges because it is a large new cross-border transmission project that requires dozens of federal and state permits and local coordination.”

ALLETE’s Minnesota Power is building the southern portion of the line, which will run from the Minnesota-Manitoba border to the Blackberry Substation near Grand Rapids, Minn. It has yet to secure right-of-way easements and faces opposition from affected landowners.

The project has already undergone one re-siting, since the original proposed border crossing route was rejected following a review by state and federal agencies. “ALLETE argues that it may face similar siting challenges as [siting] proceedings progress,” FERC said.

The line will primarily deliver hydropower from Manitoba Hydro, which will own 49% of the project and pay $558 million to $710 million of the total cost. Minnesota Power will own the remaining 51% and estimates its cost at $158 million to $201 million.

The line is projected to go into service in 2020.

December 22, 2015

MISO: Coal Retirements, Gas Prices, Flexibility Key to CPP Compliance Costs

By Amanda Durish Cook

CARMEL, Ind. — Additional retirements of coal-fired generation could increase MISO production costs by as much as $97 billion over 20 years, according to preliminary results of the RTO’s near-term analysis of the Clean Power Plan. The results were presented to the Planning Advisory Committee on Dec. 16.

The study compared a base assumption — no additional coal retirements beyond the 12.6 GW expected under the Mercury and Air Toxics Standards (MATS) — with incremental retirements ranging from 7 GW (12.5% of MISO’s remaining nameplate capacity) to 28 GW (50% of capacity).

A loss of 7 GW would increase MISO’s production costs by a net present value of $87.3 billion over 20 years, increasing to $97.4 billion for 28 GW. MISO estimates the MATS retirements will increase production costs by $90.7 billion over 20 years.

The figures do not include costs of additional electric and natural gas infrastructure needed to support replacement generation. Those costs weren’t included in the scope of work for the near-term analysis but will be included in a long-term analysis that will run through late 2018.

The analysis found that the Clean Power Plan’s building blocks have the potential to reduce carbon emissions generated in the footprint from more than 500 million tons annually to below 350 million tons.

MISO ran 675 simulations assuming annual demand growth of 0.8% and natural gas prices ranging from $2.30 to $6.30/MMBtu. The RTO also made calculations based on renewable sources making up 14%, 20% and 30% of energy production.

Gas Price Impact

MISO said the price of natural gas could be the biggest variable in the cost of compliance. “Beyond gas prices, it’s hard to isolate the single biggest variable,” Jordan Bakke, senior policy studies engineer at MISO, told the PAC.

Bakke said MISO staff have found that the more flexible the compliance strategy — mixing generation resources and strategies such as trading programs — the lower compliance costs will be.

During the Advisory Committee’s “hot topic” discussion of the final rule Dec. 9, stakeholders were divided on how involved MISO should become in guiding compliance paths. (See Lead or Follow? MISO Stakeholders Split over RTO’s Role in CPP.)

Flora Flygt, strategic planning and policy adviser at American Transmission Co., said she appreciated MISO’s work and asked that MISO post materials as soon as they’re prepared so stakeholders can spend more time with the information ahead of meetings. PAC Chair Bob McKee said the early release of modeling information would lead to more productive meetings.

Based on a revised timeline, MISO’s near-term analysis will last until February, overlapping with the mid-term analysis slated to begin in January. Additional results from the near-term analysis will be presented at the January PAC meeting.

“It’s only an initial step into this suite of work,” Bakke summed up. “What’s on tap for the January [meeting] is looking at regional versus state compliance and rate-based versus mass-based compliance. So we have a huge trove of information coming out. The bulk of the analysis is yet to come.”

December 22, 2015

FERC Seeks $2.5M Fine in CAISO Market Manipulation

By Rich Heidorn Jr.

FERC last week ordered ETRACOM and its principal trader Michael Rosenberg to respond to allegations that they manipulated the CAISO energy market in a scheme that allegedly netted $315,000 in profits (IN16-2).

FERC issued an Order to Show Cause accusing the company of submitting virtual supply transactions at the New Melones intertie at the CAISO border in order to affect power prices and benefit its congestion revenue rights (CRRs) at that location.

The Office of Enforcement alleged that in May 2011, ETRACOM submitted and cleared uneconomic virtual supply transactions intended to artificially lower the day-ahead LMP and create import congestion at New Melones. ETRACOM’s virtual supply offers resulted in a $42,481 loss, while staff estimates that ETRACOM earned $315,000 in profits on its CRR positions.

FERC staff estimated that the alleged scheme resulted in the market overpaying all New Melones CRR source holders, including ETRACOM, $1.5 million. The overpayment was funded by New Melones CRR sink holders and revenue inadequacy.

FERC is seeking a $2.4 million civil penalty from the company and a $100,000 penalty from Rosenberg in addition to disgorging its profits.

ETRACOM and Rosenberg issued a statement Tuesday denying FERC’s allegation, which they said “inappropriately cherry picks evidence it asserts shows manipulation, ignores other evidence that is exculpatory, misstates facts, and reaches illogical and erroneous conclusions.”

The statement was released through attorney Robert Fleishman, of Morrison & Foerster in Washington. It said the losses the company suffered on its virtual supply offers trades were not the result of manipulation but of market flaws.

FERC enforcement staff “belittles—and in many instances outright ignores—the serious, undisclosed market design flaws and software, modeling and pricing errors plaguing the New Melones Intertie in May 2011,” they said.

“Indeed, the market was so flawed that CAISO ceased trading at New Melones soon after May 2011 and admitted that it was ‘inappropriate’ to have created that market in the first place. But for CAISO’s market design, approved by FERC, and modeling errors at New Melones, the trading outcomes alleged by FERC would not have occurred. Undoubtedly, this was not a ‘well-functioning market.’”

The company said it will prove that the company “rationally attempted to profit from a record hydro event in May 2011 that would (and, two months later, in fact did) cause congestion at the New Melones Intertie node.”

“Staff’s erroneous conclusions therefore rely exclusively on economic evidence of ETRACOM’s losses in May, without any documentary support for its theory of a manipulative scheme. Market participants everywhere should be concerned by staff’s actions in light of such scant evidence, which effectively would subject any trading losses incurred from legitimate risk-taking to baseless manipulation claims divined after the fact.”

ETRACOM said it has not had any opportunity to take formal discovery, interview witnesses, or subpoena documents and will “vigorously” defend itself.

December 22, 2015

Company Briefs

Iberdrola USA and UIL Holdings have closed their merger and adopted “Avangrid” as the name for the U.S. operations arm of Spanish conglomerate Iberdrola. It began trading on the New York Stock Exchange on Thursday under the symbol AGR.

The combined company has eight electric and natural gas utilities with a rate base of approximately $8.3 billion serving 3.1 million customers in New York and New England. Its renewable energy subsidiary is the second largest wind energy producer in the U.S. with 5.6 GW of wind generation capacity sited in 53 wind farms in 18 states.

James P. Torgerson, CEO of UIL Holdings, became CEO of Avangrid.

More: Avangrid

AES Gets Access to 1 GWh of Batteries

AES announced it is gaining access to 1 GWh worth of lithium ion batteries from Seoul-based LG Chem, which it plans to deploy in its Advancion platform, which provides large-scale grid energy storage to utility companies.

The energy storage business is “definitely moving to a new level this year,” says John Zahurancik, president of AES Energy Storage. AES says large batteries can displace peaker plants and reduce emissions.

GTM Research says AES could deploy hundreds of megawatts in Ireland and California as early as 2016. It forecasts that the U.S. will deploy a record 192 MW of energy storage in 2015.

More: AES; The Washington Post

Duke to Bury Coal Ash in Landfill at SC Site

Duke Energy Carolinas filed plans to construct a lined, on-site landfill to bury 2.2 million tons of coal ash at the W.S. Lee Station in Belton, S.C. The company plans to excavate coal ash now contained in two ash basins and a structural fill area on the property.

The new contained system will keep the coal ash from polluting the surrounding soil and groundwater, the company said.

The company already is in the process of shipping nearly 1.4 million tons of coal ash from one ash pond at the site to a landfill in Homer, Ga.

More: Duke Energy

Alliant, We Energies Reach Accord on New Power Plant

Alliant Energy says it has settled a dispute with We Energies concerning a $700 million natural gas-fired power plant it plans to build in Beloit, Wis.

WE was trying to block the project, arguing that Alliant should instead purchase power from its Port Washington plant. Alliant said it wouldn’t be able to meet its long-term energy needs through that plant.

The terms of the settlement were not disclosed, but Alliant said it would create opportunities for joint ownership of power plants in the future with WE’s parent company, WEC Energy Group. Alliant said the agreement also provides for joint development of renewable energy projects.

More: Journal Sentinel

NEI CEO Fertel Retiring at End of Next Year

Marvin Fertel, who helped lead the nuclear industry’s response to the Fukushima accident in Japan, will retire at the end of next year as president and chief executive of the Nuclear Energy Institute. Fertel has led the trade group since 2009.

Fertel has been with the organization since its formation in 1994 and became vice president of Nuclear Economics and Fuel Supply at that time. He was named senior vice president and chief nuclear officer in 2003. NEI is looking to hire a successor.

More: NEI

Kipp, 48, Takes over as El Paso Electric’s CEO

Mary Kipp, the first female chief executive in El Paso Electric’s 114-year history, and also its youngest, assumed leadership of the West Texas utility last week.

“It feels really good” to be CEO, the 48-year-old Kipp said a few hours after taking over the company’s top job. She has overseen several departments during her seven years at the company and said she plans no big changes.

The company’s board of directors appointed her in September 2014 as the successor to Tom Shockley, 70, who retired Dec. 15 after almost four years in the job.

More: El Paso Times

ALJ says OCC Should Support OG&E’s Proposed Solar Tariff

The Oklahoma Corporation Commission should approve Oklahoma Gas and Electric’s plan to levy demand charges on customers who install rooftop solar and other distributed generation, an administrative law judge recommended Dec. 14.

Judge Jacqueline Miller also said the commission should direct OG&E to provide further evidence of the costs distributed generation customers impose on the grid in its upcoming rate case. In the meantime, Miller recommended the commission allow the utility to impose the proposed tariffs on distributed generation customers for one billing cycle, subject to refund. She faulted OG&E for not providing enough information from a checklist developed last year by the commission’s public utility division for distributed generation issues.

OG&E filed its case under Senate Bill 1456, which Gov. Mary Fallin signed last year. It allows regulated utilities to propose new tariffs if they can show distributed generation customers are being subsidized for their grid-connection costs by other customers.

More: The Daily Oklahoman

PSO to Replace Smart Meters in Tulsa Area Following Recall

Public Service Company of Oklahoma said last week it is replacing “a small number” of Tulsa-area smart meters because of a manufacturer’s defect “that could cause the screen to go blank.”

PSO sent a letter to nearly 25,000 customers Dec. 14 announcing the recall. The Tulsa-based utility said only residential meters are at issue, and fewer than 10% are affected by the recall. PSO installed roughly 300,000 smart meters in the area this year, about 240,000 at residential properties. None of the General Electric meters have failed, but PSO said it wants to get ahead of any potential issues.

The smart meters have been controversial with some customers, who claim they pose a threat to health, privacy and safety. In October, an administrative law judge recommended approval of PSO’s plan to allow residential customers to opt out of smart meters. The recommendation is pending with the Oklahoma Corporation Commission.

More: Tulsa World

Kinder Morgan Joining with Mystery Company to Build Plant

FERC filings indicate that Kinder Morgan is partnering with a company to build a natural gas-fired generation plant in New York state, but there’s no clue as to the name of the company or the location of the proposed plant.

A Kinder Morgan spokesman said the agreement with the other company and other details are subject to a confidentiality agreement. Kinder Morgan has proposed a pipeline in New York, the Northeast Energy Direct project. The power plant would probably be a customer of the pipeline.

Tennessee Gas Pipeline, a unit of Kinder Morgan, is seeking FERC approval for the pipeline in the fourth quarter of 2016, with construction starting in January 2017 and an in-service date of Nov. 1, 2018. The company estimates the project will cost $5.2 billion.

More: The Daily Star

NRG says Waukegan Station will Keep Burning Coal

NRG Energy confirmed that its Waukegan Generating Station in Illinois will continue using coal as a fuel source, despite protests by environmentalists.

The plant on Lake Michigan’s waterfront was subject to protests by environmentalists who attended a Waukegan City Council meeting last week. The protests spurred Waukegan Mayor Wayne Motley to promise to arrange a meeting with the plant’s owner.

NRG spokesman David Gaier said Waukegan is included in the company’s long-term plan to invest $567 million in its Illinois assets. “We made it very clear what we are going to do [in Waukegan],” he said, adding that “we continue to operate the plant effectively and safely” using coal. “They’re welcome to express their opinions,” he said of the protesters, “but we make our plans based on the market.”

More: Chicago Tribune (subscription required)

Duke Contends New Solar Projects Competitive

Duke Energy assured North Carolina regulators that the new solar projects it is building are competitive with those its affiliate, Duke Energy Progress, purchased through a competitive bidding process.

Duke wants to transfer to its own fleet the certificates of need that are required to build a 60-MW plant and a 15-MW project. Those projects were secured initially by a bidding process that included independent developers.

Duke argued that it can build the projects itself, providing better benefits to customers. “We have the option of really investigating the site and deciding what makes sense for us to build in each case,” a company spokesman said. “We can scale it up or drop it some, depending on what we need.”

More: Charlotte Business Journal

PSE&G Names Bridges VP Electric Operations

John A. Bridges, who has held various positions with Public Service Electric & Gas since 1987, was named vice president of electric operations. Since starting with the company, Bridges has been a supervising engineer, construction manager, operations and resource manager and division manager.

“He understands what it takes to provide our 2.2 million electric customers with safe, highly reliable service during blue-sky days and in severe weather,” said Ralph LaRossa, PSE&G president and chief operating officer.

More: PSE&G

Eversource Sets Reliability Record

Eversource Energy says the past year was the most reliable on record.

Outages were less frequent and power was restored more quickly than in any previous year in which those events were tracked, according to statistics released by the utility.

Since 2012, the frequency of outages across Eversource’s service area has decreased by 18% and restoration times have decreased by 26%, according to a company spokesman.

More: New Hampshire Union Leader

December 22, 2015

FERC Rules Against Entergy over ‘Bandwidth’ Accounting

FERC last week affirmed an administrative law judge’s 2014 ruling finding fault with Entergy’s accounting in in its fourth annual bandwidth filing (ER10-1350).

The commission agreed with much of the judge’s order, which found Entergy did not properly include the fuel inventory balance as an input to the bandwidth formula for the 2009 test year and failed to include accumulated deferred income tax for its Waterford 3 nuclear plant west of New Orleans. The judge also ruled Entergy made an error in its accounting for the amortization period for the sale and leaseback of Waterford 3.

FERC gave Entergy — which was joined by the Arkansas and Louisiana commissions in intervening — 60 days to make a compliance filing.

Also last week, FERC denied the Louisiana Public Service Commission and Entergy’s request for a rehearing of its December 2014 order, which set for hearing and settlement judge procedures the use of Waterford 3’s accumulated deferred income tax in the bandwidth remedy (EL10-65).

Entergy’s allocation of production costs among its half-dozen operating companies under its system agreement has been a source of continuing disagreement.

The companies essentially operate as one system, although each has different operating costs. Payments are made annually by Entergy’s low-cost operating companies to the highest-cost company in the system, using a “bandwidth” remedy that ensures no operating company has production costs more than 11% above or below the system average.

Regulators in Entergy’s states have regularly challenged the annual bandwidth filings, which began in 2007.

— Tom Kleckner

December 22, 2015

GSA Opposes Exelon-Pepco Settlement

By Suzanne Herel

D.C.’s largest consumer of electricity, the federal government, is urging the Public Service Commission to reject Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc. unless the applicants revise their settlement to provide benefits for non-residential customers.

“The terms of the settlement agreement are not consistent with the public interest because there are no direct benefits … for commercial customers, and the [customer investment fund] benefit for residential ratepayers is less than face value,” the General Services Administration said in an initial brief filed Dec. 16.

It also called for a two-year rate freeze and a cap on Pepco’s cost recovery on the development of four proposed microgrids.

“While the $25.6 million residential base rate credit is provided to cover base rate increases occurring from the merger closing through March 31, 2019, residential rates will increase during that period, and the terms of the settlement agreement anticipate that the credit may be insufficient to cover all residential increases approved during that period,” GSA said, predicting that any benefit would be offset by an ensuing “rate shock.”

To blunt a rate hike, GSA proposes a two-year freeze of distribution rate cases, through Dec. 31, 2017.

GSA noted that the effects of the settlement stretch beyond the district. Federal customers, which represent 25 to 30% of Pepco’s annual distribution and load delivery revenue, pay their utility bills with money from taxpayers in all 50 states and the district.

In response to GSA’s filing, Exelon and Pepco released a joint statement saying, “All customers, including the GSA, will benefit from merger commitments now before the commission, including improvements in service reliability, investment in sustainability and the economy of the district and synergy savings that will go back to customers through rates that are lower than they would be absent the merger.”

GSA: Comments Should Count

GSA’s comments came after the deadline for the agency to become a legal part of the case. But it asked the PSC to afford it as much weight as those from other intervenors, pointing out that it was given party status in the beginning of the proceedings and participated in settlement conferences ordered by the commission.

It also had filed a motion against re-opening the case after the applicants submitted a settlement agreement reached with Mayor Muriel Bowser’s administration and opposed the truncated rehearing schedule, saying it didn’t give the non-settling parties enough time to prepare an informed response.

Regardless of deadlines, comments continue to pour in to the PSC, which has said the case has received the most public input of any in the commission’s more than 100-year history.

Among them are more than 40,000 signatures of district residents that Exelon and Pepco collected in support of the merger as well as resolutions from neighborhood groups opposing the deal.

The merger, which would create the nation’s largest utility, was rejected in August by the D.C. PSC after being approved by FERC and regulators in Delaware, Maryland, New Jersey and Virginia.

In early October, the applicants reapplied with a settlement supported by former critics — Bowser, People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine — that included $78 million in public benefits. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)

Bowser Comes Under Scrutiny

Last week, Bowser’s reversal was hit with a new volley of criticism when radio station WAMU reported that the head of a political action committee formed by her supporters had been hired by Exelon to lobby city officials to support the merger.

FreshPAC was able to skirt fundraising limits due to a loophole in D.C. law. It was disbanded in November after being accused of creating a “pay-to-play” political environment.

Records show that Exelon hired the committee’s chairman, Earle “Chico” Horton III, as a lobbyist on Sept. 30. The settlement was made public Oct. 6.

The Washington Post editorial board called on Bowser to release emails and other materials documenting the negotiations that went into the settlement.

“There is nothing illegal, or all that unusual, about companies hiring lobbyists with connections they think will serve their interests,” the Post wrote. “But what is legal is not always right, and the fact that someone who was raising thousands of dollars to advance the mayor’s interests was at the same time carrying water for a company that wanted something from the government is more than unseemly.”

The PSC is expected to render its decision in early 2016. (See Exelon, Pepco Make Final Case for Merger in DC PSC Hearings.)

A decision also is pending on an appeal of the Maryland Public Service Commission’s 3-2 vote approving the merger.

On Dec. 8, the Office of the People’s Counsel and the Sierra Club argued before Queen Anne’s County Circuit Judge Thomas Ross that the merger was not in the public interest. He is expected to issue an order on or around Jan. 8.

December 22, 2015

PSEG, P3 Group Appeal FERC Rulings on PJM Capacity Rules

Public Service Enterprise Group and the PJM Power Providers Group (P3) asked the D.C. Circuit Court of Appeals last week to overturn two FERC orders approving PJM capacity market rules.

PSEG challenged FERC’s Oct. 15 ruling denying rehearing of a 2014 order approving PJM’s changes to its capacity auction demand curve and related parameters (ER14-2940). (See FERC Upholds PJM’s Capacity Market Parameters.)

PSEG and P3 had disputed PJM’s use of an 8% cost of capital used in cost of new entry (CONE) calculations, saying it was too low because it relied on corporate-level data for publicly traded independent power producers and did not reflect riskier, project-level financing.

Separately, P3 appealed FERC’s refusal to rehear a 2013 order approving PJM’s revisions to a rule designed to mitigate buyer-side market power in the capacity market (ER13-535).

The ruling addressed the minimum offer price rule (MOPR), which PJM added to its auction protocols in 2006 amid concern that load could have an incentive to suppress market clearing prices by offering supply at less than a competitive level.

P3 challenged FERC’s rejection of PJM’s proposal to extend the MOPR mitigation period mitigation from one to three years. It also contended the ruling conflicted with its prior rulings on buyer-side market power mitigation regarding NYISO. (See FERC won’t Rehear PJM MOPR Ruling.)

— Rich Heidorn Jr.

December 22, 2015

Solar to Shine Under ITC Extension

By Tom Kleckner

The budget bill signed by President Obama on Friday — which appears to mark the beginning of the end for renewable energy subsidies — will accelerate the growth of solar power in the next several years, analysts say.

The bill extends the solar investment tax credit indefinitely, albeit at a reduced level after 2019.

The wind production tax credits were extended through 2019, also at reduced levels after 2016.

The Solar Energy Industries Association predicted U.S. solar power capacity will triple to 95 GW by 2022 as a result of the incentives — enough to supply 3.5% of the nation’s electricity, up from less than 1% in 2014. SEIA CEO Rhone Resch predicted solar jobs will grow from 200,000 to 340,000.

Greentech Media’s GTM Research is even more bullish, saying it expects solar capacity to quadruple to nearly 100 GW by 2021. The ITC extension will lead to $40 billion in incremental investment in solar between 2016-2020, it said.

“There’s no way to overstate this — the extension of the solar ITC is the most important policy development for U.S. solar in almost a decade,” said MJ Shiao, director of solar research for GTM Research.

By 2020, said Shayle Kann, senior vice president at GTM Research, “more solar will be installed each year than was added to the grid cumulatively through 2014.”

Wall Street agreed, with solar companies Enphase Energy, SunEdison and SolarCity each rising by 32% or more last week.

“With the extension of tax credits, solar becomes cost-effective for new customer demographics and in more states. Without it, it could take years for that to be true,” Shiao told RTO Insider. “With the ITC extension, the next five years will see 25 GW of solar that otherwise wouldn’t be installed.”

The bill extends the 30% solar investment tax credit through 2019, dropping gradually to 22% by 2021. The credit is eliminated for homeowners beginning in 2022 but continues indefinitely at 10% for commercial installations. Projects that come online by the end of 2023 will qualify for larger credits based on the year in which construction began.

Shiao said the extension provides a bridge to EPA’s Clean Power Plan, whose requirements don’t take effect until 2022. The CPP anticipates additional wind and solar energy making up for reduction in fossil fuel generation.

GTM Research said the extension will have the biggest impact on utility-scale solar, boosting deployments 73% through 2020 with utility-scale contracts dropping below $0.04/kWh.

Without the bill, the ITC would have dropped to 10% for non-residential and third-party-owned residential systems and zero for host-owned residential systems in 2017.

Bloomberg New Energy Finance said developers would have installed 11.9 GW of solar panels in the U.S. next year in a rush to beat the end of the ITC. With the extension, BNEF said, 2016 will likely see the addition of about 9.1 GW, a drop of almost one-quarter.

BNEF had predicted solar installations would drop by as much as 71% in 2017. It now predicts an increase of 5.5% over 2016.

IHS Technology said the U.S. solar installations would have dropped by 6.5 GW in 2017 from 2016 without the extension.

End Game for Wind?

The story is a bit different for the more mature and competitive wind industry.

The wind production tax credits were extended at 2.3 cents/kWh for 2015 and 2016, dropping by 20% in each of the following three years to 40% of the current level by 2019. Without additional congressional action, it would expire in January 2020.

The American Wind Energy Association said in a statement Friday that the bill ensures “stability for 73,000 American wind industry workers … and [wind] investors.”

AWEA said the PTC has helped more than quadruple U.S. wind power, with installed capacity rising from 16.7 GW at the beginning of 2008 to 69.5 GW by the third quarter of 2015. The organization credits the PTC with helping advance wind turbine technology, leading to a 66% drop in the cost of wind energy over the last six years.

Beth Soholt, executive director of the renewable energy advocacy group Wind on the Wires, issued a statement applauding Congress’ action.

“This extension gives these renewable energy industries the certainty they need to plan for the future and mitigates the boom-bust cycles that are so very detrimental,” Soholt said.

When renewable energy tax credits were allowed to briefly expire in 2013, wind farms saw a 92% drop in their installation and some 30,000 jobs were lost. After the PTC was renewed, the wind industry recovered all but 7,000 jobs by the end of 2014, according to AWEA data.

With the extension, according to BNEF, the U.S. will add 44 GW of wind capacity by the end of 2021, a 76% increase over the 25 GW it said would have been built without any subsidies.

Wall Street’s reaction to the PTC was more muted, with Vestas Wind Systems A/S, the world’s largest turbine maker, finishing last week up by more than 8%, albeit at a five-year high.