A power plant owner affiliated with The Blackstone Group is asking state and federal regulators for expedited approval to buy two coal-fired power plants in western New York (15-E-0580).
Riesling Power is seeking to buy the 668-MW Somerset facility in Niagara County and the 312-MW Cayuga facility, which is operating under a controversial reliability support services agreement.
Both plants are owned by Upstate New York Power Producers, formed by a group of bondholders that purchased the plants from the bankrupt AES Energy East for $240 million in 2012. The filing asks for approval by the New York Public Service Commission’s Dec. 17 meeting. The buyer said all personnel would remain in place and the plants would continue operating. The purchase price was not disclosed.
“Expedited approval is appropriate here because the proposed transfer does not raise any issues regarding retail energy sales to captive ratepayers or market power concerns in the competitive wholesale markets in New York and is consistent with commission precedent,” the state filing states.
Upstate New York Power, whose largest stockholders are the California Public Employees’ Retirement System (CalPERS), Carlyle Strategic Partners, J.P. Morgan Investment Management and Marathon Asset Management, asked for FERC approval of the deal by Nov. 24 (EC15-214).
Riesling is a wholly owned subsidiary of Bicent Power, which in turn is 95.6%-owned by GSO Capital Partners. GSO represents the credit-oriented business of The Blackstone Group, one of the largest players in the leveraged buyout business. Upstate New York Power had hired Blackstone in 2014 to sell the plants, according to Power Finance and Risk.
Neither Riesling nor Bicent own generation in New York, the filing states.
The Plants
Cayuga, a 60-year-old pulverized coal-fired power plant on the eastern shore of Cayuga Lake in Lansing, N.Y., is operating under a RSSA with New York State Electric and Gas (NYSEG). The plant is also the subject of a PSC proceeding considering whether to repower it from coal to natural gas.
Plant owners had proposed to mothball the facility in early 2013, but NYISO and NYSEG determined the plant was needed for system reliability. A one-year RSSA was ordered by the PSC. With no suitable alternatives identified, the commission approved a second RSSA that expires June 30, 2017.
NYSEG, Niagara Mohawk and several stakeholders are promoting the proposed Auburn Transmission Project Phase 2 as an alternative to the Cayuga repowering (13-T-0235). The project has been endorsed by PSC staff.
Somerset, a pulverized coal-fired power plant in Barker, N.Y., on the southern shore of Lake Ontario that began commercial operations in 1984, has been described as too distant from existing natural gas pipelines for a conversion.
The largest taxpayer in its home county, Somerset is a merchant plant selling its output into NYISO.
Energy Highway
When New York Gov. Andrew Cuomo proposed the Energy Highway in 2012 to bring power from generation plants upstate to load centers in and around New York City, Upstate New York Power responded that the plants could play an “important role” for the proposal.
“New York’s energy needs require a diverse blend of fuel-type resources to provide the state’s residents and businesses with a dependable and affordable energy pool,” the company said. “Upstate New York Power Producers looks forward to being a part of the solution.”
It said the two plants are in compliance with the current environmental regulations and “well positioned” to meet future regulations, having invested in technologies including flue gas desulfurization and selective catalytic reduction to reduce sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions.
Last month, the PSC staff took a step toward making the highway a reality, recommending transmission routes that would help move 1,000 MW of upstate generation. (See NYPSC Staff Recommends $1.2B in Transmission Projects.)
Somerset, located in Zone A, is connected to the main 345-kV east/west transmission corridor with NYSEG at the Kintigh Switchyard. Cayuga, in Zone C, connects with NYSEG at the Milliken Switchyard at 115 kV.
WASHINGTON — A key House committee last week approved what would be the first comprehensive energy legislation in eight years, but hopes for passage dimmed after Republican amendments eroded bipartisan support.
H.R. 8, the North American Energy Security and Infrastructure Act of 2015, cleared the House Energy and Commerce Committee 32-20 on Wednesday with support from only three Democrats. The bill includes measures to improve energy infrastructure, resilience and reliability while increasing scrutiny of RTOs and FERC.
Pallone (left) and Upton.
A preliminary draft of the bill had passed a subcommittee unanimously. But Wednesday’s markup devolved into partisan sniping after Chairman Fred Upton (R-Mich.) replaced the original bill with a 208-page amendment that stripped gas and electric infrastructure funding sought by Democrats. The amendment also includes provisions that would speed the approval of liquefied natural gas export terminals and repeal current law requiring that federal buildings phase out the use of fossil fuel-generated energy.
The changes left Rep. Frank Pallone (D-N.J.), the ranking Democrat on the committee, fuming. “This bill only aims to help polluters in my opinion,” he said. “It continues to ignore the impact of climate change, which remains the biggest threat to our energy security and way of life.”
Upton said the bill is intended to create jobs, improve infrastructure and ensure affordable energy. “While it has been difficult to find bipartisan consensus on as many fronts as I would have liked, I believe we have written a substantive, thoughtful bill,” he said in opening the committee markup.
Congress has not approved a comprehensive energy bill since the Energy Independence and Security Act of 2007. While the House bill is unlikely to pass as is, many of its provisions could find their way into final legislation if bipartisanship prevails.
The Senate Energy and Natural Resources Committee passed its own legislation, the Energy Policy Modernization Act, on July 30 by a bipartisan 18-4 vote.
The package, crafted by Chairwoman Lisa Murkowski (R-Alaska) and ranking member Maria Cantwell (D-Wash.), also would expedite LNG projects and streamline the federal permitting process. It includes measures to improve energy efficiency and cybersecurity and encourage hydropower and geothermal development.
Below is a summary of the House bill’s major provisions affecting the electric industry:
RELIABILITY
Fuel Security
The bill would require traditional vertically integrated utilities to incorporate “reliable generation” into their integrated resource plans, defining it as generation facilities with firm-fuel contracts, dual-fuel capability or sufficient on-site fuel to operate “for the duration of an emergency or severe weather conditions.” (Section 1107)
The requirements would not apply to companies engaged in competitive, unbundled retail electric sales.
FERC Reliability Review
FERC, in consultation with the North American Electric Reliability Corp., would be required to conduct reliability analyses of any federal rule affecting electric generators that is expected to result in an annual effect on the economy of at least $1 billion. The FERC review would evaluate the impact of the rule on electric reliability; resource adequacy; the nation’s electricity generation portfolio; the operation of wholesale markets; electric transmission lines; and natural gas pipelines. (Section 1108)
RESILIENCE
Hardening
The bill would require all utilities to develop plans for improving the resilience of their systems against physical sabotage, cyberattacks, electromagnetic pulses, geomagnetic disturbances, severe weather and earthquakes. Among the measures that utilities may consider are the hardening of distribution facilities; technologies that can isolate or repair problems remotely, such as advanced metering and monitoring and control systems; cybersecurity measures; distributed generation; microgrids and non-grid-scale energy storage. (Section 1107)
State regulators “shall consider” authorizing spending on such improvements, the bill says.
The legislation also establishes a competitive grant program for states and local governments for spending on resilience and reliability. (Section 1201)
Strategic Transformer Reserve
The bill would authorize the creation of a stockpile of large power transformers and trailer-mounted mobile substations to recover from the threats listed above. (See “Hardening.”)
The issue caught Congress’ attention as a result of the April 2013 rifle attack on Pacific Gas and Electric’s Metcalf substation and a campaign by former FERC Chairman Jon Wellinghoff to raise awareness of the grid’s vulnerabilities. Wellinghoff cited a 2013 FERC analysis that he said concluded that an attack that disabled nine critical substations could cause an extended blackout in the continental U.S. (See Report: Sabotage Threat Uncertainty Could Lead to Wasteful Spending.)
The Energy Department would be required to develop a plan for the reserve and identify preferred funding options, including fees on owners and operators of bulk-power systems and critical electric infrastructure, federal appropriations, and public-private cost sharing. (Section 1105)
Grid Security Emergencies
If the president declares a grid security emergency, the Secretary of Energy would have authority to order measures to protect or restore the reliability of critical electric infrastructure. (Section 215A)
FERC
Merger Authorization
It would limit FERC review of merger and consolidation acquisitions to those of $10 million or more. (Section 4222)
FERC Enforcement
FERC would be required to create an Office of Compliance Assistance and Public Participation to “promote improved compliance with commission rules and orders.” (Section 4211)
The proposal is an apparent response to complaints by some in the Washington energy bar that FERC’s Office of Enforcement, formerly headed by Chairman Norman Bay, is unfair and heavy handed. (See Gates, Powhatan Say FERC Enforcers Didn’t Share Crucial Info.)
The office would “promote improved compliance” with commission rules through outreach and publications and, “where appropriate, direct communication with entities regulated by the commission.’’
The provision is intended to provide entities subject to FERC regulation “the opportunity to obtain timely guidance for compliance with commission rules and orders” — an opportunity FERC says it already offers through “no-action” letters.
RTOs/ISOs
GAO Study
The Government Accountability Office would be required to conduct reports on each RTO’s and ISO’s “market rules, practices and structures.” (Section 4221)
The grid operators would be judged on a number of issues, including whether they produce just and reasonable rates; facilitate fuel diversity, reliability and advanced grid technologies; and promote “equitable treatment of business models, including different utility types.”
GAO also would evaluate the transparency of grid operators’ governance structures and stakeholder processes as well as the transparency of dispatch decisions, including the need for out-of-market actions and the accuracy of day-ahead unit commitments.
The report also would review how well grid operators facilitate “the ability of load-serving entities to self-supply their service territory load.”
The American Public Power Association, which opposes mandatory capacity markets, said the bill doesn’t go far enough. The group said the bill doesn’t address problems faced by public power utilities “forced to participate in the FERC-blessed mandatory capacity markets and is silent on the issue of self-supply for such LSEs.”
APPA, which represents more than 2,000 community-owned, not-for-profit utilities, said it wants the legislation changed to allow wholesale markets to “become more affordable and workable for public power utilities that are willing and able to build a variety of power generation facilities if not blocked from doing so by rules skewed toward certain market participants.”
Financial traders could benefit from a requirement that RTOs ensure “the proper alignment of the energy and transmission markets by including both energy and financial transmission rights in the day-ahead markets.”
Industry sources said the provision would encourage more widespread use of products similar to PJM’s up-to-congestion trades and ERCOT’s point-to-point congestion hedges.
Capacity Markets
RTOs and ISOs operating capacity markets would be required to provide to FERC an analysis of how the markets use competitive forces and include “resource-neutral” performance criteria. FERC would be required to report to Congress on whether each market meets the criteria and make recommendations for those that don’t. (Section 215B)
INFRASTRUCTURE
Deadlines
A final decision on a federal authorization for gas pipelines would be due no later than 90 days after FERC issues its final environmental document, unless a schedule is otherwise established by federal law. (Section 1101)
It would require the Energy Department to act on applications for LNG export facilities within 30 days of the conclusion of reviews under the National Environmental Policy Act. (Section 3006)
Frank Macchiarola, executive vice president for government affairs at America’s Natural Gas Alliance, praised the bill, saying that it “recognizes and seeks to maximize the opportunities presented by our nation’s domestic energy abundance.” ANGA represents independent natural gas exploration and production companies in North America.
Carbon Capture
The Energy Department would be required to evaluate all carbon capture and sequestration projects funded by the agency every two years. (Section 1109)
Hydropower
The bill would reauthorize hydroelectric production incentives through fiscal year 2025 and require FERC to minimize infringement on private property rights in issuing hydropower licenses. (Sections 1301-1304)
FERC would be authorized to issue exemptions from licensing requirements for development of new hydropower projects at existing non-powered dams.
It would build on changes in two bills enacted in 2013 that streamline regulations on small hydropower sites. A 2012 Energy Department report said the powering of non-powered dams could unlock 12 GW of generating capacity. (See Tiny Hydro Projects Joining Generation Mix in PJM.)
APPA said it was disappointed that the bill does not include “substantive” licensing reform.
“The current hydropower licensing process must be reformed so that public power and other utilities can increase reliable emissions-free hydropower generation without unnecessarily prolonged resource agency review,” it said.
The bill would provide special relief for one hydro project, however.
The developers of the proposed hydro project on the U.S. Army Corps of Engineers’ W. Kerr Scott Dam on the Yadkin River in North Carolina would have an additional six years to start construction under the bill. Wilkesboro Hydropower has proposed adding a turbine that would generate 2 MW at the unpowered dam.
FERC granted the developers a license in July 2012 giving them two years to begin construction and five years to complete it. In May 2014, FERC granted Wilkesboro Hydropower a two-year extension (P-12642-007).
Under the Federal Power Act, FERC told the developers, the deadline for starting construction may only be extended once.
VALLEY FORGE, Pa. — The Markets and Reliability Committee voted overwhelmingly Thursday to raise the energy market offer cap to $2,000/MWh in a move that outgoing CEO Terry Boston called “the stakeholder process at its best.”
The MRC approved the new cap by an unweighted 84-17 margin, after which the Members Committee gave final approval by voice vote.
Boston said the Board of Managers would approve the new framework and PJM would be filing a Tariff change with FERC within a couple of weeks.
He apologized for not having the Tariff language ready before the vote, saying, “We were not as optimistic as we should have been about this getting approved this morning and afternoon.” He said the language would be made available to members a few days before the FERC filing.
Boston appeared touched by the vote, which comes as his seven-year tenure nears its end. “In the first meeting of the year, after this was voted down last year, I begged for consensus,” he recalled.
There was a smattering of applause when the vote was revealed at the MRC, and many who had sparred this year over the issue offered praise to PJM staff, each other and the four entities who agreed to withdraw their own proposals in favor of the simplified plan: Direct Energy, Old Dominion Electric Cooperative, PJM Power Providers Group (P3) and the Independent Market Monitor.
“It’s really cool that we were able to pull this off given the short time frame,” said Marji Phillips of Direct Energy, which had initiated the first of the four proposals. “I want to compliment everyone who supported this — especially when I was yelling at you at the last meeting.”
Pepco Holdings Inc.’s Gloria Godson called the vote “a beautiful thing to behold.”
The Details
The proposal caps cost-based offers at $2,000/MWh and allows them to set LMPs, with market-based offers allowed to equal cost-based ones. Generators with approved fuel-cost policies claiming costs above $2,000/MWh would be compensated through after-the-fact review and subsequent make-whole payments.
Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during extreme conditions such as the 2014 polar vortex.
Jeff Whitehead of Direct Energy, whose proposal would have raised the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers, said the company was willing to back the compromise because it ensures “that as much generator compensation cost is recovered as possible in energy prices, which are hedgeable, and something load servers can compete on.”
“Uplift is not [hedgeable] and is a cost that gets rolled into risk adders that get passed on to consumers,” he added.
Likewise, David “Scarp” Scarpignato of Calpine said P3 didn’t believe the consensus proposal offered the “proper price formation,” but the group was willing to support it because it does allow generators to recover costs and raises the level that can set LMPs.
Temporary Change; FERC Action Expected
Some of those who opposed raising the cap previously — or thought the compromise was insufficient — were willing to support what is now assumed to be a temporary solution. FERC on Sept. 17 announced its intention to take action on offer caps and other price formation issues. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
Exelon’s Jason Barker, who at the last meeting on the issue had criticized the framework, supported it Thursday as “an improvement over the status quo” and said he hoped FERC would improve on the filing. “We will look forward to FERC … recognizing flaws inherent in this proposal,” he said. (See Consensus Near on PJM Energy Market Offer Cap?)
Similarly, Dynegy’s Jason Cox said, “Dynegy reluctantly supports this compromise as a way to ensure that our costs are covered until FERC acts. We believe that we should not allow market distortions and continue to support potential massive uplift during critical periods.”
Susan Bruce of the PJM Industrial Customer Coalition said her group continued to have concerns over the proposal but offered support in return for a promise from the Market Monitor and PJM that there would be “robust reporting” on offers between $1,000, the current cap, and $2,000.
Delaware, Maryland Unconvinced
Representatives of state commissions generally opposed the proposal.
John Farber, public utility analyst for the Delaware Public Service Commission, asked that PJM consider releasing information about the heat rates of the generators setting the clearing price.
Walter Hall of the Maryland Public Service Commission said his agency remained unconvinced of a need to raise the cost cap.
Jim Jablonski of the Public Power Association of New Jersey pointed out that PJM fared better this past winter, which saw colder temperatures, than it had during the previous season’s polar vortex.
And, he said, “Capacity Performance is designed to provide a financial incentive to perform whenever needed and designed to eliminate future emergencies. Reliability, therefore, in our view is protected. We do not think a change is warranted. Two thousand dollars is not supportable except as a compromise, has no factual basis and definitely is going to be open to challenge.”
MISO staff said Friday they will recommend three economic projects be included in the 2015 MISO Transmission Expansion Plan. The projects in Southern Indiana, East Texas and Central Arkansas have a projected cost of $281 million, including $85 million that PJM will pay for its share of the Indiana project.
Digaunto Chatterjee, MISO’s director of economic studies, told a special meeting of the Planning Advisory Committee that staff selected the Duff-Rockport-Coleman 345-kV project from among three under consideration near the RTO’s eastern seam with PJM in Southern Indiana.
MISO will pay $67.2 million for the Duff and Coleman substations and a 28.5-mile single circuit between them. PJM will cover the cost of the $38.7 million double circuit line plus $46.5 million in upgrades at the Rockport substation.
Chatterjee said the MISO portion of the project — the Duff and Coleman substations and a 28.5-mile single circuit between them — has a benefit-cost ratio of 16.1 based on MISO’s estimated cost of $67.2 million.
The project, expected in service in 2021, should eliminate congestion around Newtonville and Coleman and provide slightly higher economic benefits than the Duff-Coleman alternative. MISO’s cost will be the same as the $67.2 million Duff-Coleman because PJM will pay $85.3 million for improvements that will allow it to eliminate the special protection scheme at its Rockport substation.
“It’s no difference to us whether it’s one project or two projects connecting with each other,” Chatterjee said.
The PJM portion of the project includes two 765/345-kV transformers in Rockport and a 14-mile double circuit between the substation and Duff-Coleman.
Reacting to concern that the PJM portion of the project could result in unexpected costs, Chatterjee said staff “will make it clear to the board MISO stakeholders don’t want any issues from the PJM side to keep us from going ahead with the project.”
“We fully expect Duff to Coleman will be connected to Rockport,” he told the PAC, “but we won’t let PJM’s processes interfere with our portion of the project.”
Chatterjee said he had received a commitment from PJM saying that will approve the project and pay the incremental costs. (See “AEP Agrees to Pay Share of Market Efficiency Project” in MISO Planning Advisory Committee Briefs.)
East Texas Project
MISO is also recommending two economic projects in its South region, including a two-part construction/rebuild that would ease congestion around an East Texas load pocket.
MISO recommends constructing a new 230-kV transmission line between the existing Lewis Creek substation and a new 345/230-kV substation that will cut into the Grimes-Crocket 345-kV line. In addition, it will rebuild the Newton Bulk-Leach 138-kV line.
MISO South will get projects in East Texas (L) and Central Arkansas (R).
Chatterjee said the project cleared the benefit-cost ratio under two different future generation scenarios, with a B/C of 1.5 assuming future generation inside the load pocket and a 2.88 B/C with generation added outside the pocket.
The project has an estimated cost of $122.5 million and a projected in-service date of 2021. It would ease congestion on three 138-kV lines.
Arkansas Project
The third project, rebuilding the Mabelvale-Bryant South 115-kV line, would reduce congestion in the southwest Little Rock area. It has a projected cost of $6.1 million and a weighted B/C ratio of 5.88, with an estimated 2020 in-service date.
Staff will accept stakeholder input on the three projects through Oct. 2. Previous feedback and MISO’s responses to the South projects have been posted in the Oct. 2 Market Congestion Planning Study meeting materials.
The PAC will consider MTEP 15 during its Oct. 14 meeting, before the plan goes on to the System Planning Committee in October and Board of Directors in December.
A FERC administrative law judge will attempt to settle TransSource’s complaint against PJM concerning the costs of three network upgrades that the company says are being inflated by transmission owners (EL15-79).
TransSource alleges that PJM has refused to provide the company with files relevant to the system impact studies showing the underlying costs of the upgrades, which the company says is in violation of the RTO’s Tariff. PJM maintains that it provided TransSource with all the necessary data and that it is under no obligation to provide the specific files the company is requesting.
The Independent Market Monitor last month requested that FERC settle the dispute. (See PJM Monitor Asks FERC to Resolve TransSource Dispute.) PJM responded by saying it was willing to informally meet with the Monitor, TransSource and the relevant transmission owners to discuss the studies. TransSource rejected this, supporting the Monitor and insisting on a formal process.
The commission said Thursday that it could not rule based on the record before it and set the case for hearing and settlement procedures.
More than 170 people attended the Independent Power Producers of New York’s 30th annual Fall Conference at the historic Gideon Putnam resort in Saratoga Springs, a two-day affair of golf and industry talk. See RTO Insider’s coverage:
The MISO board’s Markets Committee met at Potomac Economics headquarters in Fairfax, Va., last week to review the Independent Market Monitor’s quarterly metrics report and its monitoring procedures.
Monitor David Patton, president of Potomac Economics, also provided a preliminary evaluation of extended locational marginal pricing (ELMP), which he said had resulted in very small price changes for most locations.
Patton recommended MISO use more online peakers under ELMP, which he said would increase their price impacts. Only about 1% of the resources are eligible to set prices under ELMP. The program, which was implemented in March, is designed to reduce uplift charges by incorporating all offer costs into the market clearing price.
“Real-time prices should fully reflect the cost of dispatchable resources, but ELMP allows offline units to set the price when you have congestion,” Patton said. “This could be resolved by quick-starting offline units.”
Summer Performance Competitive and Reliable
Patton said the MISO market performed “competitively and reliably” during the summer, despite record peak loads in MISO South in July.
Considerably lower gas prices than a year ago drove down MISO’s average system-wide energy prices for the June-August period. Real-time prices fell 17% from last year’s $28.78/MWh, and day-ahead prices fell 19% to 29.26/MWh.
Congestion was typical for the summer, with both day-ahead and real-time congestion similar to last year. Patton said the market’s price convergence was generally good, with the exception of congested areas in Texas and Louisiana.
“We’re seeing people put in virtual load on one side of the constraint,” he said, “and a virtual bid on the other side.”
The market continues to respond slowly to congestion-related price differences in the day-ahead and real-time markets, Patton said.
The Monitor said “growing pains” in market-to-market coordination with SPP have resulted in some inefficiency and settlement disputes. When the non-monitoring RTO dominates the flows, MISO and SPP have seen swings in dispatch flows over M2M constraints.
“The SPP constraints move so fast,” Patton said. “I’d like to see the two RTOs develop protocols to determine who is in charge of the constraint.”
The summer’s above-average temperatures in MISO South resulted in the extensive commitment of peaking units in the day-ahead and real-time markets.
Some day-ahead hourly commitments exceeded 700 MW per hour, three times the typical rates. Additional real-time commitments resulted in more than 1,100 MW of peaking units running each hour during the quarter, double the amount from last summer.
MISO Monitor’s Procedures
Patton also reviewed with the committee Potomac’s scope and processes as MISO’s Monitor.
The Monitor downloads market data every 30 seconds to allow it to observe market participants’ actions in the market, identify flaws in market rules and support the RTO’s market power mitigation. Potomac develops and maintains the production software that does all the work, but that software is owned by MISO.
“You can only do efficient monitoring if you have highly automated systems,” Patton said, noting Potomac’s ability to run tests and screens in the background and to send automatic notifications. He said he partly attributes the costs between different markets to RTOs’ varying reliance on automated systems.
Potomac also performs monitoring duties for ERCOT, ISO-NE, NYISO and the Regional Greenhouse Gas Initiative. Its 24-member staff includes four Ph.D. economists and a half-dozen software engineers.
Operations Report
MISO staff delivered a positive monthly operational report at the meeting, saying the RTO’s reliability, markets and operational functions all performed well in August.
MISO South set a new peak load of 32.7 GW on Aug. 10, surpassing the previous record of 32.6 GW on July 29. However, system-wide average and peak loads declined 3.6% and 4.2%, respectively, compared to July’s numbers.
Energy prices (based on the average of MISO’s active hubs) for the summer months were below $30/MWh and were at the lowest levels in recent summer months.
Wind production — 2,362 GW in August — increased nearly 20% from July and 75% from August 2014 (1,348 GW). Though wind output typically is at its lowest levels in August, it reached its highest level as a percentage of total generation in five years, at 4.3%.
Exelon on Monday asked the D.C. Public Service Commission to reconsider its rejection of the company’s proposed $6.8 billion acquisition of Pepco Holdings Inc.
The filing came as D.C. Mayor Muriel Bowser’s office confirmed that it is seeking to negotiate a settlement with the companies. “We are engaged in substantive discussions with the companies on a settlement agreement that would address, in a new application, the administration’s concerns,” City Administrator Rashad Young, who is leading the negotiations, said in a statement. “Any settlement agreement would be presented to the PSC for review, public comment and final determination.”
In a radio interview Sept. 25, the day after opponents of the deal rallied outside her office, Bowser had declined to confirm whether she was engaged in negotiations. (See DC Mayor Tight-Lipped on Exelon-Pepco Deal.)
Exelon’s appeal, submitted on the last day of the 30-day appeal period, takes issue with two of the PSC’s findings: that the merger was not in the public interest and that it would not be in the public interest for the commission to identify additional conditions that could make it so.
The 43-page filing maintains the commission’s ruling contained “various errors of law” and reiterated the benefits that the company said the district would receive, quoting at length from CEO Christopher Crane’s direct testimony. (See CEO Crane to DC PSC: Exelon Committed to Jobs, Ratepayers.)
Exelon said the merger would “yield tremendous benefits by unlocking millions of dollars of synergy savings; facilitating the sharing of best practices; enhancing the reliability of service; ensuring the continuity of a skilled workforce; creating net positive job growth in the District of Columbia; guaranteeing Pepco’s active participation in and support of the District of Columbia’s many civic and charitable organizations; and providing Pepco and the District of Columbia with a partner uniquely well-suited to help the District of Columbia advance its sustainability goals quickly and effectively.”
Crane referred to the negotiations with Bowser’s office in a press release late Monday. “Since the Public Service Commission explained why it didn’t approve the merger last month, we’ve worked to learn what’s most important to the district – and we are responding,” Crane said.
“Exelon’s attempt to breathe new life into its takeover of Pepco should be rejected by the D.C. Public Service Commission,” the opposition group Power DC responded. “The PSC unanimously rejected Exelon’s attempt to buy Pepco in August for a very simple reason: the merger is not in the public interest. Nothing Exelon said today will change that fact. Exelon’s business model is fundamentally at odds with the district’s ability to control its own power supply.”
In making its decision last month, the PSC said it weighed the proposal on seven factors of public interest, among them the effects on ratepayers and shareholders, market competition and preservation of natural resources and the environment. (See DC Halts Exelon’s Acquisition of Pepco Holdings; Pepco Stock Tumbles.)
More than half of the Advisory Neighborhood Commissions and nearly half of the 12-member City Council remain opposed to the deal. The Office of People’s Counsel and the attorney general’s office also have advised against approval without significant concessions.
The acquisition was approved by regulators in all remaining jurisdictions: New Jersey, Maryland, Delaware, Virginia and FERC.
SARATOGA SPRINGS, N.Y. — New York Public Service Commission Chairman Audrey Zibelman last week acknowledged legislators’ concerns over the state’s energy costs but gave no indication that the commission would relent on lawmakers’ demands that it release data on generators’ finances.
Zibelman
Forty State Assembly members and nine state senators signed a letter last week asking the commission to release in full the annual reports submitted by the state’s generation owners.
Generators contend that the reports should be treated as trade secrets because they contain data on their revenues, expenses and profits.
“I understand that people are worried about price confidentiality; I can assure you that the commission takes very seriously its role around maintaining confidentiality and of course we’re reviewing the [disclosure request] against the law,” Zibelman told the fall conference of the Independent Power Producers of New York.
“But I think we can’t disabuse ourselves of the fact that one of the things that’s very important in our markets is to have public confidence and when you have 48 [sic] Assembly people saying ‘We have some concerns,’ we need to start talking about how do we allay those concerns and make sure that there is confidence throughout the state.”
Legislators say the information is essential to determining whether electric competition has resulted in “just and reasonable” rates.
“For too long the industry has operated in secrecy, which is damaging to New Yorkers across the state, who are paying the third highest rate for electricity in the entire country,” the legislators wrote. “In a time where the PSC is taking steps to lead New York into the energy future with [Reforming the Energy Vision], and it’s proceeding to evaluate energy affordability for low-income utility customers, we ask that the PSC do everything it can to make sure that the industry is operating responsibly.”
Cost-Benefit Analysis on REV
Durant
The REV initiative also came under criticism at the IPPNY conference from Michael Durant, New York state director of the National Federation of Independent Business.
Durant said he feared REV could result in a “bridge to nowhere” and that his organization will support legislation calling for a cost-benefit analysis for the initiative.
“For REV, we don’t know what it’s going to cost, we don’t know how long it’s going to take and nobody can predict what the end result is,” he said, adding that energy costs are a top concern for his small business members.
Second Request for Release of Reports
The release of the generators’ reports was first requested by Assemblyman James Brennan (D-Brooklyn), who says consumers are being overcharged “billions” by power generators in a flawed market that needs to be “re-regulated” (13-01283 and 11-M-0294).
Brennan, chair of the Assembly Committee on Corporations, Authorities and Commissions, said much of the redacted information is available from other public sources.
“The wholesale electric power industry seeks to conceal its profits from the public by claiming that the bidding system would be undermined if rivals knew each other’s costs,” Brennan said in a statement. “But our evidence shows that argument is without merit because the bidder’s identities are easily ascertainable and their costs are easily calculated from regular federal filings made by these companies.”
The lawmaker’s first Freedom of Information Law request in 2014 was rejected by the PSC’s records access officer, who said the information consisted of protected trade secrets, and that disclosure would cause havoc in the operation of the power markets. Kathleen H. Burgess, secretary of the state Department of Public Service, agreed, rejecting Brennan’s appeal.
Brennan filed a second request in May, which was also rejected by the records access officer. On Aug. 27, Brennan again appealed to the secretary.
This time around, Brennan’s request included an affidavit from energy consultant Robert McCullough that said that heat rate information from power plants is publicly available in the Environmental Protection Agency’s national electric energy data system database.
IPPNY responded with an affidavit that said the database contains estimates and not the actual heat rates that the PSC requires. The records officer agreed.
IPPNY and nuclear plant owner Entergy argued that the disclosure issue had already been decided. “No new facts or circumstances have developed over the past year to warrant a different result now,” an attorney for Entergy wrote in response to the appeal.
Brennan had asked for decision by Sept. 11, but the commission will not rule on his demand for disclosure until Oct. 19. “In light, however, of the length of the appeal, and particularly the 190-page McCullough affidavit, and of the issues raised in the oppositions received thus far from IPPNY and Entergy, a decision on the appeal will require some period of time,” Burgess wrote on Sept. 11.
New York Public Service Commission staff on Tuesday recommended that three transmission developers move to the next stage in its AC Transmission initiative to eliminate bottlenecks for downstate load centers.
After evaluating 22 transmission proposals and several non-transmission alternatives from four developers, the staff recommended two main projects: the upgrade of the 91-mile, double-circuit 220-kV Edic-New Scotland-Rotterdam line to 345 kV and the upgrade of the 51-mile, double-circuit 115-kV Knickerbocker-Pleasant Valley line to a 115/345-kV double circuit.
The PSC is expected to vote in December on the projects, which have an estimated price of $1.2 billion (12-T-0502, et al).
The proposed routes would satisfy Gov. Andrew Cuomo’s Energy Highway goal to bring 1,000 MW of power generated upstate to areas of high demand in southeastern New York and New York City.
“Many of the proposals and critiques were responsive to the governor’s call for transmission solutions that maximize the re-use of existing rights of way so as to minimize impacts on the sensitive landscapes of New York. … Staff’s recommended portfolio successfully avoids the opening of new transmission rights of way and also avoids a new crossing of the scenic Hudson River,” the report said. (See Tx Plan to Open NY Choke Points Without New ROWs.)
The developers are NextEra Transmission, North American Transmission and a coalition of utilities and the New York Power Authority known as the New York Transmission Owners. Another private developer, Boundless Energy, was disqualified because its projects, while environmentally sound, did not provide a positive cost-benefit ratio, according to the report.
The Edic-New Scotland-Rotterdam line runs through the Mohawk Valley from Oneida County, near Utica, to Albany County. The Knickerbocker-Pleasant Valley line in the Hudson Valley runs from Rensselaer County to Dutchess County.
Following approval by the PSC, NYISO would be directed to issue a request for proposals to build the two segments. PSC staff said the two upgrades would provide more benefits if other developers were given an opportunity to bid on the project rather than solely selecting the NYTOs.
“The NYTOs and NextEra should be invited to apply to build both segments, and NAT should be invited to build the … Knickerbocker to Pleasant Valley segment,” staff wrote.
Staff said that while “other developers will be able to participate in the NYISO process” and potentially win the contracts, only the three companies will be reimbursed for the costs of participating if they are not selected.
To operate at full capacity, the Knickerbocker-Pleasant Valley project also would require upgrades to Orange and Rockland Utilities’ Rock Tavern terminal and increasing the 11-mile 69-kV Chester-Shoemaker-Sugarloaf line in Orange County to 138 kV.
In an interim report filed in July, PSC staff said that a spring announcement that a 720-MW power plant project had secured financing led to additional study of the Hudson Valley alternatives. (See NYPSC Staff Narrows Transmission Alternatives.)
The additional capacity would allow wind power generation, mostly sited in the northwestern part of the state, to more easily gain access to downstate New York markets.
