The D.C. Office of the People’s Counsel and the district government asked the Public Service Commission Friday to reconsider its March 23 approval of Exelon’s $6.8 billion acquisition of Pepco Holdings Inc., saying the commission’s rewrite of settlement terms was improper.
Friday was the deadline for the nine parties to the case to request such reconsideration. Aside from OPC Sandra Mattavous-Frye and D.C. Government, the only qualified party to do so was Grid 2.0, which advocates for distributed generation. (See Grid 2.0 Asks DC PSC to Reconsider Merger Approval.)
Exelon and Pepco didn’t wait for the deadline, closing the merger the day of the PSC’s approval. (See Exelon Closes Pepco Merger Following OK from DC PSC.) Last week, Pepco asked Maryland regulators for a 10% rate increase for most of its customers.
Mattavous-Frye said the decision was important for future cases. In her application, she asked that the PSC reopen the record and allow all parties to comment or reject Exelon and Pepco’s unilateral request for adoption of new merger terms as being “procedurally improper.”
“I strongly believe that the manner in which the decision was reached was legally flawed,” she said. “If the flaws in this order are not corrected, it will erode the trust and confidence of consumers and all parties that practice before the commission.”
The D.C. government, in a filing submitted by Attorney General Karl Racine, said, “By unilaterally modifying the terms of the non-unanimous settlement agreement and approving the terms of the revised non-unanimous settlement agreement as a resolution on the merits, the commission committed a series of procedural and substantive errors that require it to reconsider and vacate Order No. 18148.
“The order will have a chilling effect on future settlement negotiations because parties will fear that, in agreeing to proposed settlement terms, they run the risk of the commission proposing and approving alternative settlement terms without the parties’ consent.”
If the PSC does not reconsider and vacate the order, it should reject the merger or approve the non-unanimous settlement agreement subject to “such additional terms as the commission determines will satisfy the public interest,” the filing said.
Mattavous Fry Source DC OPC
Mattavous-Frye and the government opposed the initial merger proposal, which the commission rejected last August. They signed on to a later settlement brokered by Mayor Muriel Bowser’s office in October. District officials withdrew their support after two of three PSC commissioners revised that settlement, saying the changes substantially weakened protections for ratepayers.
If the commission stands by its decision, parties may seek relief from the D.C. Circuit Court of Appeals.
FERC last week ordered MISO and PJM to make changes in their interregional transmission planning process, granting in part a 2013 complaint by Northern Indiana Public Service Co. (EL13-88).
NIPSCO, which operates on the seams of the RTOs, pointed to “significant congestion costs [and] operating issues” along the seam and noted that no transmission project had ever been approved under the RTOs’ joint operating agreement.
The company said that although market-to-market redispatch had helped day-to-day operations, the RTOs had not developed solutions to long-standing congested flowgates. It proposed several changes that it said would incent cross-border transmission projects. (See FERC Considering NIPSCO Proposals on PJM-MISO Seam.)
First, it recommended the RTOs run their cross-border transmission planning process at the same time as their regional transmission planning cycles, rather than after them.
FERC said it agreed with NIPSCO that the existing open-ended planning process can delay the “identification, analysis and potential approval of beneficial interregional economic transmission projects.”
The commission gave MISO and PJM 60 days to revise the JOA “to include timely, specific deadlines for each step in the coordinated system plan study process” and establish a deadline for how much time it should take from proposal to approval.
“We also find that … it is unclear how the coordinated system plan study in the JOA interacts and aligns with the [MISO Transmission Expansion Plan] and the [PJM Regional Transmission Expansion Plan],” FERC ruled. “A clear process laid out in the JOA may resolve these disagreements and help provide a consistent understanding of the process for all stakeholders.”
FERC denied NIPSCO’s request that the MTEP, RTEP and JOA processes follow a common timeline. But it asked MISO and PJM to submit an informational filing within 120 days describing how it could do so and what impacts that would have on the RTOs’ planning process as well as interregional coordination with neighboring regions.
The commission also denied NIPSCO’s suggestion that MISO and PJM be required to conduct a coordinated system planning study on a regular basis. Requiring that “even when the RTOs’ annual review of transmission issues finds it unnecessary would not be an efficient use of MISO’s, PJM’s and stakeholders’ time and resources,” FERC said.
NIPSCO also recommended that the RTOs develop a single model using the same assumptions in the cross-border transmission process. FERC rejected that suggestion but directed MISO and PJM to “explore the potential use of a joint model with the same assumptions and criteria” and submit an informational report on the issue.
Finally, NIPSCO asked that the RTOs use a common set of criteria in evaluating cross-border efficiency projects.
FERC agreed with NIPSCO that the current cost and voltage thresholds can remove from consideration certain projects that could benefit both regions. It ordered MISO to reduce its minimum voltage threshold for interregional economic transmission projects from 345 kV to 100 kV and eliminate the $5 million cost threshold for such projects. (See PJM, MISO to Scrap $20M Threshold for Joint Tx Projects.)
It also ordered the removal of the requirement for a third, separate benefit-cost analysis for the combined regions.
WASHINGTON — The U.S. Senate overwhelmingly passed its first major energy bill in almost a decade Thursday but faces a tight calendar to reach agreement with the House, where Republicans approved their own measure with little Democratic support.
President Obama has threatened to veto the House bill but expressed support for most of the Senate provisions.
House Energy and Commerce Committee Chairman Fred Upton (R-Mich.) said he hopes to craft a compromise that can clear both houses and win Obama’s approval.
Senate Energy Committee Chair Lisa Murkowski (R-Alaska) acknowledged some House Republicans won’t be pleased that the Senate bill permanently authorized the Land and Water Conservation Fund and did not end the controversial Department of Energy loan guarantee program.
“My hope is that the House takes a look at the strong vote over here,” she said in a press conference with the committee’s top Democrat, Sen. Maria Cantwell (D-Wash.), after the vote. “I think we have demonstrated, with the process that we have used here on the Senate side … we can work through issues. [The] calendar is a little more challenging,” she added, noting that a formal conference committee would require that both houses be in session at the same time.
Cantwell praised Murkowski’s stewardship of the bill. “Because of her willingness to work in a bipartisan fashion — have an open amendment process in the committee and on the floor and consider so many pieces of legislation by our colleagues — I think that was what the success in today’s resounding vote is about.”
The 424-page Senate bill authorizes increased spending on energy research, improves cybersecurity protections and encourages more efficient buildings and vehicles. It also adds taxpayer protections to the loan guarantee program and streamlines federal approvals of electric transmission, pipeline, hydropower and LNG facilities.
Compromises
The bill won broad support by largely sidestepping polarizing issues such as climate change and oil and gas production. Nevertheless, there were some provisions that displeased environmentalists, including its support for accelerated approval of LNG export terminals.
And although it won the backing of the U.S. Chamber of Commerce, the conservative Heritage Foundation decried it as a “continuation of government meddling in the energy economy.”
Below is a summary of the provisions of interest to electric industry stakeholders. Bill sections are identified in parentheses.
Efficiency
Buildings
Noting that the federal government is the single largest energy consumer in the country, the bill directs the head of each federal agency to reduce their building energy intensity by 2.5% annually through fiscal year 2025 (1017).
It also requires the Secretary of Energy to revise federal building energy efficiency performance standards (1016); develop an efficiency metric for data centers (1011); and support the updating of energy efficiency provisions in model building codes (1001).
The bill encourages federal agencies to implement energy and water conservation measures (1006) and extends the maximum length of utility energy service contracts from 10 to 25 years (1005).
It repeals the requirement that new federal buildings and those undergoing major renovations phase out fossil fuel-generated energy consumption by 2030 (1015).
The legislation also blocks a final rule establishing a condensing furnace efficiency standard absent a finding by an advisory group convened by the Energy Secretary that a nationwide requirement is “technically feasible and economically justified” (1103).
Appliances
The bill cites a prediction that appliance standards put in place for more than 30 products since 2009 will reduce consumers’ utility bills by almost $1.8 trillion by 2030. It requires the Energy Department to establish a rebate program to encourage the replacement of inefficient electric motors (1101) and transformers (1102).
Manufacturing
The manufacturing sector, which represents 12% of the gross domestic product, uses almost one-third of the primary energy in the U.S.
The legislation amends the Energy Independence and Security Act (EISA) of 2007 to direct the Energy Department’s Industrial Assessment Centers to coordinate with other federal manufacturing programs, the National Laboratories and energy service and technology providers, and the department’s Office of Energy Efficiency and Renewable Energy to provide onsite technical assessments to manufacturers seeking efficiency opportunities (1201).
It also expands the scope of technologies covered by Industrial Assessment Centers to include smart manufacturing technologies and provides the centers tools and training to provide technical assistance to manufacturers (1202). It directs the department to provide small and medium manufacturers access to high-performance computers at the National Labs (1203).
Vehicles
The bill authorizes research and development to reduce petroleum use in passenger and commercial vehicles (1306) and improve the efficiency of medium- to heavy-duty commercial, vocational, recreational and transit vehicles (1308) and Class 8 truck and trailer platforms (1309).
Cybersecurity
About 32% of reported cyberattacks involve the energy sector, the bill says. The bill establishes the Energy Department as the agency responsible for energy sector cybersecurity protections and directs it to carry out cybersecurity research and development (2002).
The bill adds a new section to the Federal Power Act (224) that gives the Secretary of Energy authority to order actions necessary to protect the grid from cyber threats in an emergency. It also orders FERC to permit entities to seek recovery of prudently incurred costs as a result of an emergency. The new FPA section also prohibits the unauthorized disclosure of critical electric infrastructure information (CEII) by FERC personnel or agents of the commission (2001), a provision apparently inspired by the controversy over former FERC Chairman Jon Wellinghoff’s public disclosures of information from a confidential FERC analysis on grid security. (See FERC Criticism of Ex-Chair Mounts.)
The bill also creates programs to identify and test supply chain vulnerabilities and response capabilities between the DOE and other agencies. It increases industry participation in information sharing and expands the department’s cooperation with the intelligence community (2002).
Infrastructure Permitting
Electric Transmission
The Energy and Natural Resources Committee report on the bill refers to the federal permitting process for electric transmission as “notoriously slow and unpredictable,” citing NERC data that transmission projects take six to 15 years to engineer, site, permit and construct.
The Obama administration sought to improve coordination in federal agencies’ review of electric transmission facilities on federal land through a 2009 memorandum of understanding signed by nine agencies. To accelerate the deployment of seven pilot transmission projects, the administration in 2011 created a Rapid Response Team for Transmission with the nine signatories.
The bill codifies the Rapid Response Team and creates an ombudsperson at the Council of Environmental Quality to resolve intra-agency disputes or delays related to transmission permits (2309).
Section 215 of the Federal Power Act is amended to require regional reliability entities to submit to Congress and FERC within six months, and every three years thereafter, a report describing the state of and prospects for electric reliability. They are also required to submit a reliability impact statement (RIS) on any proposed federal rule they believe will affect the reliable operation of the bulk power system. The statements are to be submitted to FERC for forwarding to the proposing agency, which “shall consider the RIS and include a detailed response in the final rule” (4301).
It also provides liability protection for generators ordered by DOE to run for grid reliability to insulate them from litigation over exceeding their environmental permits (4303).
Gas Pipelines
The Senate committee called the federal review process for natural gas pipelines “complex and cumbersome,” noting that the Secretary of the Interior lacks authority to grant pipelines permission to cross National Parks — requiring an act of Congress. “This issue has come to the forefront in recent years because of growing demand for natural gas in the Northeast and rising natural gas production in the Marcellus Shale (e.g., Pennsylvania). The limited infrastructure that connects the two regions is greatly constrained, and the area is comprised of significant National Park holdings,” the committee said.
The bill designates FERC as the lead agency for all federal authorizations and National Environmental Policy Act compliance related to natural gas transportation; says such authorizations should be issued within 90 days after applications are deemed complete; and orders FERC to establish an interagency schedule and refer all interagency disputes to the CEQ for resolution. Agencies that do not act within the 90-day deadline would be required to explain delays to Congress and FERC and provide plans for eliminating the delay (3103).
LNG
Five LNG projects in Louisiana, Florida, Texas and Maryland have received final authorizations to export a total of 6.5 Bcfd. As a result, the Energy Information Administration expects the U.S. to become a net exporter of natural gas by 2020.
LNG projects require both Energy Department authorization to export the commodity and approval from FERC, which has jurisdiction over the terminals. The bill requires the department to issue a final decision on applications to export natural gas to countries that do not have free trade agreements with the U.S. within 45 days after completion of NEPA reviews of LNG facilities (2201).
The bill also requires the Secretary of Energy to submit within one year a study on the economic impacts of LNG exports, addressing manufacturers’ concerns that exports will raise domestic gas prices (3102).
Distributed Energy Resources, Storage
The bill requires the Secretary of Energy to conduct R&D and a demonstration program to address challenges identified in DOE’s 2013 Strategic Plan for Grid Energy Storage (2301). The department would be required to develop model grid architecture and a set of future scenarios to examine the impacts of different combinations of resources on the grid and to determine whether any additional standards should be developed to ensure the interoperability of the grid and associated communications networks (2302).
The bill requires the Energy Department within two years to provide Congress with an evaluation of the performance of the electric grid and a description of the quantified costs and benefits associated with the changes evaluated under the scenarios developed under section 2302 (2306).
When requested by a state, the department would partner with states and regional organizations to develop electric distribution plans (2307).
It also requires RTOs and ISOs to submit reports to FERC within six months identifying barriers to the deployment of distributed energy systems and microgrid systems. The reports must include potential changes to the operational requirements and costs associated with interconnecting these resources (2310). The Energy Department is to undertake a study of net energy metering (2311).
Hydropower
The bill seeks to simplify what the Senate committee called “a Byzantine” relicensing process for hydropower projects, noting that more than 250 projects totaling 16 GW will need new licenses in the next decade. Hydropower supplies 6% of U.S. electricity and 52% of renewable power. Relicensing currently takes eight to 10 years.
To reduce permitting backlogs, the bill designates FERC as the agency responsible for setting a binding licensing schedule and coordinating all federal authorizations. It authorizes the chairman of the CEQ to resolve interagency disputes to ensure timely decision making; requires FERC administrative law judges to preside over trial-type hearings on issues of material fact; and orders the commission to establish a voluntary pilot program to consider a regionwide approach to hydropower licensing (3001).
It also extends through fiscal year 2025 the incentives for hydroelectric production and efficiency improvements contained in the Energy Policy Act of 2005 (3002). It reinstates the license for Clark Canyon Dam in Montana and extends the deadline for starting construction for three years (3003). It also authorizes FERC to extend the construction deadline for the Gibson Dam in Montana for six years (3004).
Geothermal Energy
The bill urges the Secretary of Interior to ‘‘significantly increase’’ geothermal production from federal lands and asks the U.S. Geological Survey to identify sites capable of producing 50 GW of geothermal power within 10 years (3005, 3006).
It also allows geothermal development by co-production of electricity from oil and gas leases on federal lands (3007) and creates a noncompetitive leasing process through which existing geothermal leaseholders on federal lands can lease adjoining lands without rebidding (3008).
Research and Development Funding
The bill authorizes spending of $500 million over 10 years on energy storage R&D, $290 million through 2021 on projects involving marine and hydrokinetic energy and $2 billion on technologies to improve the grid, including microgrids. However, Congress often appropriates far less than originally authorized.
Coal, Carbon Capture
The legislation repeals the existing EPACT 2005 coal programs and establishes a new coal technology program including R&D, large-scale pilot projects and demonstration projects. It authorizes $610 million annually from 2017 to 2020, and $560 million for 2021 (3401, 3402).
Nuclear Power
It requires the Energy Department to submit a report to Congress on its ability to host privately funded fusion and fission reactor prototypes at DOE-owned sites (3501), and removes the requirement that the project be built at Idaho National Laboratory (3502).
Workforce Training
The legislation establishes the 21st Century Energy Workforce Advisory Board at the Energy Department to develop a strategy for developing a skilled workforce for the energy sector, including underrepresented populations (3601), and establishes a four-year pilot program to award competitive grants for job training programs that lead to an industry recognized credential (3602).
DOE Loan Program
The bill changes DOE’s Section 1703 loan guarantee programs created by EPACT 2005 to prohibit the subordination of taxpayer interests to those of private investors. It also sets a minimum 25% of credit subsidies to be paid by borrowers (4001) and amends EPACT 2005 to establish the terms for state participation in loan guarantees (4002).
The bill also orders the Comptroller General to issue a report on the effectiveness of DOE’s advanced fossil loan guarantee program and other incentive programs for advanced fossil energy (4003).
Energy-Water Nexus
The Energy and Interior departments are required to establish an Interagency Coordination Committee, co-chaired by the agencies’ secretaries, to identify “energy-water nexus activities” across the federal government; improve coordination of R&D activities; and create a Nexus of Energy and Water Sustainability (NEWS) office (4101).
Holding RTOs Accountable
The committee expressed skepticism about organized RTO markets, saying their low prices are undermining the finances of nuclear generation and questioning whether they are producing “meaningful price signals” to indicate where new supply is needed. Reflecting the opinions of the American Public Power Association and other critics, the committee said RTO “capacity markets have been controversial … with a number of parties calling for their reform or elimination.”
RTOs and ISOs are required to report to FERC within six months on their reliability, capacity resources, wholesale electric prices, generation diversity and the ability of public power entities to self-supply capacity (4302).
ALBANY, N.Y. — The New York Public Service Commission voted 3-1 Wednesday to allow municipalities statewide to make bulk purchases of electricity and natural gas, including renewable power (14-M-0224).
Community Solar Farm Source: NYSERDA
The Community Choice Aggregation program is part of the state’s Reforming the Energy Vision initiative to encourage the greater use of cleaner and distributed energy resources.
“The CCAs started in California and in Illinois and it was largely around aggregating supply,” NYPSC Chair Audrey Zibelman said. “I think the New York version is going to be much more about aggregating demand.”
By combining their purchasing power, communities can get the cleaner energy supplies they desire at a better price, she said. “I’m [as] excited about this element of REV as anything else we’re doing,” she added.
The commission, which started a proceeding to explore aggregation in December 2014, said CCA programs in other states have only been successful where opt-out aggregation is permitted for mass-market customers. “Opt-in aggregation has proved valuable to certain larger customer groups, but opt-out aggregation appears necessary for CCA programs to achieve the scale that will enable [energy service companies] to create meaningful benefits for mass market customers,” the commission said.
The program will be open to villages, towns and cities. Municipalities will be required to conduct a minimum two-month information and education program to potential CCA members, after which residents would have at least 30 days to respond to opt-out notifications.
Municipalities will be encouraged to design CCA programs that include integration of distributed energy resources and procurement of clean energy, both through direct procurement and opt-in programs for customers. “Since CCA programs are intended to promote greater consumer awareness and bill savings, they present a formidable opportunity to advance the state’s clean energy objectives,” the PSC said.
Municipalities that contract with energy service companies will be required to conduct open competitive processes, and contracts must “offer value to their residents through favorable pricing, significant clean energy in their energy supply portfolio or another commission-approved energy-related value-added product.”
The New York State Energy Research and Development Authority will provide technical assistance to participating communities.
Commissioner Diane Burman dissented from the order, saying she supports CCA but thought the state was moving too quickly. She said she wanted to learn first from Sustainable Westchester’s pilot program, which has not yet started. The program has 110,000 residents enrolled in 17 communities and is now mailing opt-out notices to residents.
Sustainable Westchester and a partner want to develop 10 MW of solar arrays in five locations.
“My concern is truly understanding what we’re doing in the pilot program and the lessons learned,” Burman said, adding that she feared “moving too quickly into a statewide application when we haven’t done or asked for real analysis.”
FERC will convene a technical conference May 9 to consider a proposal by New England officials that electric utilities purchase natural gas pipeline capacity (RP16-618).
The commission said the conference would examine issues raised by Algonquin Gas Transmission’s Feb. 19 petition asking FERC to allow exemptions from its capacity release bidding requirements. The proposed changes to the company’s tariff would permit “prearranged releases” of firm capacity to utilities or generation owners. Algonquin, a unit of Spectra Energy, owns a network of pipelines in the Northeast that it is proposing to expand.
“Such tariff modifications are consistent with the commission’s current policy of exempting releases pursuant to state-regulated retail access programs of natural gas local distribution companies from bidding requirements,” Algonquin wrote. The company said the exemption is needed to increase the supply of available gas in periods of high demand.
Generators have protested the petition, saying the exemption would distort the secondary market for natural gas and depress electricity prices. Other protests note that “state-regulated electric reliability programs” referenced by Algonquin either do not yet exist or are on shaky legal ground. A plan by Massachusetts regulators that would allow electric distribution companies to recover costs from ratepayers was challenged by the attorney general and is before that state’s Supreme Judicial Court.
Kinder Morgan last week scrapped plans to develop a major pipeline into New England to help supply natural gas-fired power plants, citing a lack of commitments from electric generators due to regulatory uncertainty over their cost recovery. (See related story, Kinder Morgan Suspends Northeast Energy Direct Pipeline.)
The cancellation of Kinder Morgan’s project, and New York regulators’ decision last week to deny an environmental permit to the proposed Constitution Pipeline, may improve the fortunes of a third major pipeline expansion into New England, Algonquin Gas Transmission’s Access Northeast project. (See related story, New York Rejects Constitution Pipeline.)
Two electric utilities, Eversource Energy and National Grid, own a combined 60% of the project, which would provide fuel for 5,000 MW of generation. Spectra Energy’s Algonquin Gas Transmission owns the remaining 40%. (See Algonquin Submits Pre-Filing Request for Access Northeast Pipeline.)
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
Manual 19: Load Forecasting and Analysis. Revisions remove outdated rules for legacy air conditioner and water heater cycling programs and correct formulas for end-use/weather variables.
Manual 12: Balancing Operations. Manual, Tariff and Operating Agreement changes incorporate business rules for dynamic transfers.
3. Governing Documents Enhancement and Clarification Subcommittee (GDECS) (9:30-9:40)
Changes eliminate redundant definitions and list definitions in alphabetical order.
4. Demand Response Emergency Energy Settlement Measurement and Verification (9:40-9:55)
New method changes the emergency energy default customer baseline (CBL) from the hour before to the current default economic CBL. (See “Members Endorse New Way to Measure Emergency DR,” PJM Market Implementation Briefs.)
FERC on Friday approved the controversial cost allocation of two PJM projects: a stability fix for New Jersey’s Artificial Island nuclear complex and the Bergen-Linden Corridor upgrade.
“The courts have recognized that no cost allocation method can perfectly assign costs to the beneficiaries of a transmission project, particularly in the case of a transmission grid,” FERC said in its 3-1 order approving the Artificial Island allocation proposal (EL15-95. ER15-2563). “The commission found that where a cost allocation method is accurate in a very high percentage of circumstances to which it applies, then that is a strong indicator that the cost allocation method is just and reasonable.”
Commissioner Cheryl LaFleur dissented, saying, “The record in this case clearly establishes that there is a discrete and identifiable set of transmission projects as to which [the distribution factor cost allocation (DFAX)] methodology produces an anomalous result and does not allocate costs in a manner roughly commensurate with benefits.
“It is a cliché to observe that hard cases make bad law, but unfortunately I believe that is the result of today’s orders,” she said. “Because the instant cases are discrete and identifiable and have significant rate impacts that are not roughly commensurate with benefits, a failure to grant these complaints may actually undermine a cost allocation methodology that is just and reasonable in the vast majority of instances.”
The commission in November called for an inquiry in response to complaints over the allocation for the projects and held a technical conference on the issue in January. (See DFAX: ‘Poison Pill’ or ‘Best Method’ of Cost Allocation?) It asked: Is there a definable category of projects for which the DFAX method might not be appropriate, and could a fair approach be developed for those occasions?
The Delaware and Maryland public service commissions protested the cost allocation of the Artificial Island project, virtually all of which will be paid for by customers in the Delmarva transmission zone.
They cited a study requested of PJM by the Delaware commission that found only about 10%, or $17 million, of the $169 million annual load payment savings would accrue to customers in that zone. However, those customers will be allocated about $246 million of the costs.
Critics said DFAX is inappropriate for non-flow-based fixes, such as those addressing short-circuit violations, storm-hardening or stability limits.
Said FERC: “Comments opposing the solution-based DFAX method can only point to two projects out of over 1,200 identified by PJM as raising concerns.”
The DFAX method, the commission said, “focuses on the benefits of the facility as measured through use of the facility over time rather than the reliability violation that drove the immediate need for the project.”
In the second ruling — in which LaFleur also dissented — FERC denied a complaint from Consolidated Edison and Linden VFT and upheld the assignment of an additional $91 million in cost to Con Edison for the Bergen-Linden Corridor project (ER15-2562, et al.).
“As PJM explains, the costs related to the reconfiguration are necessary to address construction challenges and the elimination of high short-circuit current issues identified by [Public Service Enterprise Group], such as no longer reusing existing underground ducts to install new 345-kV cables and substation expansion for an additional 345-kV line,” the commission said. (See Developer Questions Need for PSE&G Projects without ‘Wheel’.)
Meanwhile, the Artificial Island project faces other hurdles. After Public Service Electric and Gas submitted estimates that nearly doubled the cost of its scope of work to $272 million, PJM planners are considering reconfiguring the project.
The Delaware PSC did not return a request for comment. However, Bob Howatt, the PSC’s executive director, told The News Journal that the PSC is considering filing a motion for rehearing with FERC as a prerequisite for a court appeal. “The court process is not inexpensive,” Howatt cautioned.
Delaware Public Advocate David Bonar has estimated that Artificial Island could result in rate increases of about $3/month for residential and small businesses, while increasing rates for large manufacturers by “tens of thousands.”
Some Alternate Supplier Electric Customers Paying More
The state’s Office of Consumer Counsel says thousands of residential customers who signed up with competitive electric suppliers paid more for power than customers who stayed with the standard offers from Eversource Energy or United Illuminating.
In Eversource’s territory, customers with 18 of the 28 third-party service providers paid $48 million more than the standard offer. In UI’s service area, customers with 18 of 29 competitive suppliers paid $10 million more than standard-offer customers.
Bryan Lee, a spokesman for the Retail Energy Supply Association, said the consumer advocate “is making an unfair apples-to-oranges comparison when it compares a ‘plain vanilla’ utility standard service electricity rates with the varied and complex product offerings of competitive retail energy suppliers.”
BL England Generating Station Looking to Convert to Gas
The owners of the coal-fired B.L. England Generating Station have applied to the Department of Environmental Protection for emissions permits to convert the plant to natural gas, now that a controversial pipeline to the facility has been approved.
“It’s probably the dirtiest plant left in the state,” DEP spokesman Larry Hajna said, adding that the 52-year-old plant is one of “just a handful” that still burn coal. The plant on the Jersey Shore is owned by RC Cape May Holdings, a special purpose entity formed by Rockland Capital, Energy Investors Funds and other investors.
Environmentalists are protesting the conversion. They say the 447-MW upgraded plant actually would increase pollution because the gas-fired plant would operate daily, while only one of the plant’s current coal units is active, and it only operates 60 days a year.
Energy conservation officials have been hit with a flood of applications for the state’s solar tax credit and are on track to meet the $3 million annual cap by July.
This is the last year for the state’s 10% tax credit. A measure calling for extending the incentive through 2024 stalled during the last legislative session.
Gov. Andrew Cuomo on Thursday announced $150 million in funding to support large-scale renewable energy projects across the state to help meet the goal of 50% of electricity from renewable energy by 2030.
“This state is a national leader in combating climate change, and with this investment, we are taking our unprecedented efforts one more step toward a cleaner and greener New York,” he said. “This funding will advance large-scale energy projects, continue build[ing] a clean energy economy and generate opportunity for New Yorkers for generations to come.”
Support will be provided by the New York State Energy Research and Development Authority in its final solicitation through the main tier of the state’s renewable portfolio standard.
The next round of the NY Prize microgrid competition will provide $8 million in awards for engineering designs and business plans for community microgrids, Gov. Andrew Cuomo said.
The $40 million program is part of the Reforming the Energy Vision. The NY Prize engineering design and business plan component will award up to $1 million to each of the eight winners. The deadline for proposals is Oct. 13, 2016. The competition is administered by the New York State Energy Research and Development Authority, which is currently reviewing final reports and conducting an analysis and evaluation of the feasibility studies.
Study Says Preserved Nuclear Plants Cost-effective
Preserving upstate nuclear plants via a proposed Clean Energy Standard provides benefits that exceed the costs, according to an analysis by The Brattle Group for the Public Service Commission. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)
The nuclear component of the Clean Energy Standard is responsible for more than 50% of the program’s lifetime financial benefits from carbon avoidance, despite incurring only 21% of the program’s overall costs. Power cost savings enables an additional $3.16 billion in annual gross domestic product, according to the study.
The report was prepared for the New York State IBEW Utility Labor Council, the Rochester Building and Construction Trades Council and the Central and Northern New York Building and Construction Trades Council.
Regulators Side with Duke in NC WARN-Church Solar Deal
The Utilities Commission fined an advocacy group $60,000 for violating state law by installing a solar array on the roof of a Greensboro church and then selling the electricity directly to the church. The commission said NC WARN, by law, should have produced the power, sold it to Duke Energy, which then would have sold it to the church.
The commission said NC WARN’s direct contract with the church was impermissible because the church is located within Duke’s exclusive service area. “NC WARN knowingly entered into a contract to sell electricity in a franchised area and sold electricity without prior permission from the commission, subjecting itself to sanctions,” the commission said. It ordered the group to stop operating the solar array and to turn it over to the church.
NC WARN Director Jim Warren vowed to appeal. “The decision to impose the fine is pretty surprising,” he said. “In the past, that kind of fine has been used against outright lawbreakers.” He said the arrangement was made to test the law on electricity sales.
Health Officials Go Silent on Safety Guidance near Ash Ponds
The Department of Health and Human Services says it has stopped offering any guidance to owners of drinking-water wells near Duke Energy coal ash ponds, citing pending legislative action that would govern water testing and advisories.
“We are carefully monitoring this proposed legislation and are not able to comment further on safety recommendations until the General Assembly takes action,” a department spokeswoman wrote in an email.
The department last year issued do-not-drink notices to owners of hundreds of wells near coal ash basins because their water contained elevated levels of hexavalent chromium, but it recently notified the landowners the water was safe to drink. There are no federal or state standards for hexavalent chromium. Lawmakers say the pending legislation will clear up any confusion. “They scared these folks erroneously,” Rep. Pat McElraft said. “Everybody thought Duke was poisoning them when they weren’t.”
The state Supreme Court upheld most of American Electric Power’s 2012 rate increase, remanding part of the case to the Public Utilities Commission to review if customers should receive any refunds.
The court ruled that PUCO was correct when it approved AEP’s special “capacity charge” to make the utility whole during its transition to market-based pricing.
But the court also ruled that a portion of the rate increase was a de facto “transition charge” that added up to $508 million. Some of that, it said, could be improper.
Public Utility Commissioner Pamela A. Witmer is leaving the commission at the end of April to become vice president of government affairs at UGI Energy Services, a company that comes under the commission’s regulation.
Witmer’s five-year term ended on April 1. A Republican who was appointed by Gov. Tom Corbett in 2011, her departure leaves an important vacancy on the commission, now split evenly between Democrats and Republicans. Democratic Gov. Tom Wolf has yet to nominate a replacement.
The Public Utility Commission wants to focus greater scrutiny on the state’s three public steam heat plants.
The plants produce and deliver steam heat through pipes to business districts in Philadelphia, Harrisburg and the North Shore of Pittsburgh.
Citing the risk for accidents and a thin oversight staff at the plants, the PUC is releasing proposed regulations that will call for more inspections and reporting of steam leaks and emergencies.
The Hunt Group, the would-be buyers of Oncor, are trying to change the terms of a contentious agreement it hammered out only a month ago with the Public Utility Commission. The request for a rehearing offered a bleak assessment of the sale going through.
Minutes after the Hunt Group filed a formal request for a rehearing, PUC staff filed a statement that said the group’s separate application for a rate-setting procedure failed to meet legal requirements necessary to allow the sale to go forward. Legal deadlines loom that could make it difficult to close the purchase. The commission will meet to consider the rehearing on May 4.
The buyers want to split Oncor into two linked companies that could take advantage of a $250 million federal tax break.
The Fort Worth City Council unanimously approved a resolution directing Oncor to explain why its electric transmission and distribution rates should not decrease if its federal tax bill drops under its bankruptcy reorganization plan.
The resolution stems from last month’s approval by the state Public Utility Commission of the Hunt Group’s $18 billion acquisition of Oncor. The PUC last month deferred a decision on the rate question until 2017 at the earliest.
First Commercial Wind Farm Would Top North Mountain
Apex Clean Energy is applying to site 25 wind turbines atop North Mountain in Botetourt County in what would be the state’s first commercial wind farm.
The Department of Environmental Quality has expressed support for the project, though opponents worry that the 550-foot-tall towers and rotating blades might kill birds and bats or contribute to erosion that would contaminate streams.
Richmond Opposes FERC Permit for James River Hydro
The city of Richmond is fighting a company’s attempt to install an 8-MW hydroelectric project at Bosher’s Dam on the James River, saying the generator’s intakes could interfere with fish migration.
Energy Resources USA has filed a request with FERC to give it “priority of licensing” for the hydro project but is not yet seeking a construction permit. It is proposing to divert water at the existing dam through four 2-MW turbines.
The city said the hydro project’s proximity to a fishway might impair fish migration. “The documentation shows the intake for the facility immediately upstream of the ladder, which will adversely impact the function of the ladder,” wrote Patrick Bradley, the city’s water quality manager. “Also, the facility will effectively cut off access to the ladder for operation and maintenance purposes.”
MISO is postponing a second attempt at changing its generator interconnection queue rules while it assesses FERC feedback and awaits input from a commission technical conference next month.
The RTO will participate in the conference, set for May 13 (RM16-12, RM15-21).
“MISO still believes that reforms to the interconnection queue process are necessary to adapt to a rapidly evolving generation fleet, and we look forward to further discussions with FERC and stakeholders to move this process forward,” the RTO said in an update to the Planning Advisory Committee. (See MISO Unveils Queue Rule Transition as Wind Advocates Seek Delay.)
FERC last month rejected MISO’s proposed queue changes, saying they assumed the current backlog could be blamed on “speculative” projects and “fail[ed] to consider other potential factors” (ER16-675). Those factors included the timeliness of MISO’s queue processing and its coordination with neighboring RTOs. The commission also said a proposed milestone payment could create barriers to entry for smaller developers.
“We’re free to file again, anytime we want, but we have to address the concerns FERC has,” said Tim Aliff, MISO director of interconnection and planning.
Aliff said MISO’s Interconnection Process Task Force will survey stakeholders to determine which parts of the queue plan are salvageable. He also said some new processes — such as providing interconnection customers with models ahead of the queue entrance — might be included.
MISO also is planning a filing to comply with a FERC order requiring the RTO to charge uniform milestone payments to all external, internal and existing customers. (See FERC Orders MISO to Charge Uniform Interconnection Fees.) Aliff said that filing will be made separately from the revised queue filing.
FERC last week reiterated its 2015 order rejecting New Jersey Energy Associates’ request for recovery of costs incurred during the polar vortex of January 2014.
NJEA, which owns the 290-MW South River combined cycle plant, said it was forced to sell natural gas at a loss of $1.3 million after PJM repeatedly canceled the plant’s scheduled start time.
In its ruling Thursday, FERC said that NJEA’s request for clarification and rehearing was asking the commission for the first time to interpret the phrase “actual costs incurred.”
“NJEA’s request is beyond the scope of its original waiver request and [is] inappropriately raised for the first time in a request for clarification and rehearing of the Sept. 4 order,” it said.
Friday was the deadline for the nine parties to the case to request such reconsideration. Aside from OPC Sandra Mattavous-Frye and D.C. Government, the only qualified party to do so was Grid 2.0, which advocates for distributed generation. (See Grid 2.0 Asks DC PSC to Reconsider Merger Approval.)
NIPSCO, which operates on the seams of the RTOs, 
The commission said the conference would examine issues raised by Algonquin Gas Transmission’s Feb. 19 
“The courts have recognized that no cost allocation method can perfectly assign costs to the beneficiaries of a transmission project, particularly in the case of a transmission grid,” FERC said in its 3-1 order approving the Artificial Island allocation proposal (
In Eversource’s territory, customers with 18 of the 28 third-party service providers paid $48 million more than the standard offer. In UI’s service area, customers with 18 of 29 competitive suppliers paid $10 million more than standard-offer customers.
The owners of the coal-fired B.L. England Generating Station have applied to the Department of Environmental Protection for emissions permits to convert the plant to natural gas, now that a controversial pipeline to the facility has been approved.
Preserving upstate nuclear plants via a proposed Clean Energy Standard provides benefits that exceed the costs, according to an analysis by The Brattle Group for the Public Service Commission. (See 
The Utilities Commission fined an advocacy group $60,000 for violating state law by installing a solar array on the roof of a Greensboro church and then selling the electricity directly to the church. The commission said NC WARN, by law, should have produced the power, sold it to Duke Energy, which then would have sold it to the church.
The Department of Health and Human Services says it has stopped offering any guidance to owners of drinking-water wells near Duke Energy coal ash ponds, citing pending legislative action that would govern water testing and advisories.
The state Supreme Court upheld most of American Electric Power’s 2012 rate increase, remanding part of the case to the Public Utilities Commission to review if customers should receive any refunds.
The Hunt Group, the would-be buyers of Oncor, are trying to change the terms of a contentious agreement it hammered out only a month ago with the Public Utility Commission. The request for a rehearing offered a bleak assessment of the sale going through.
Apex Clean Energy is applying to site 25 wind turbines atop North Mountain in Botetourt County in what would be the state’s first commercial wind farm.
