Consumers Energy decommissioned the last of its Michigan “Classic Seven” coal-fired turbines in response to tighter EPA emissions restrictions. The B.C. Cobb Generating Facility on Muskegon Lake ended its 67-year run in mid-April.
The turbines were retired in staggered order in consultation with MISO. The turbines included two at B.C. Cobb, two at the D.E. Karn/J.C. Weadock Generating Complex in Essexville and three at the J.R. Whiting Generating Complex in Luna Pier.
Consumers is currently outfitting five of its operational coal-fired plants with scrubber systems to meet emissions standards.
Kentucky’s largest solar facility was inaugurated last week by Louisville Gas & Electric and Kentucky Utilities. The E.W. Brown Generation Station in central Kentucky contains about 44,600 solar panels, capable of producing 19,000 MWh of electricity annually.
“We’re embarking on a new era and introducing a new source of energy to our generation portfolio that will work in concert with our coal, natural gas and hydroelectric fleet,” Paul Thompson, chief operating officer for the PPL-owned utilities, said at an unveiling ceremony.
Thompson said the new facility will allow LG&E and KU to study how commercial-scale solar energy is impacted by factors such as cloud cover and “how it integrates with the existing generating units.”
Exelon, RES Join to Build 10-MW Energy Storage Unit
Exelon Generation and Renewable Energy Systems are joining to build a 10-MW energy storage facility in Clinton County, Ohio, that is expected to be operational by the end of the year.
RES, which operates 48 MW of storage facilities, will oversee construction of the project, which Exelon Generation will operate. The unit will comprise three tractor-trailer-sized modular units near a substation for easy interconnection with PJM.
The facility will provide frequency regulation for the RTO. “Exelon’s deployment of battery storage technology provides customers and grid operators with innovative solutions to meet their technical requirements and enhance system reliability,” said Corey Hessen, vice president of Exelon Generation Development.
Consolidated Edison is investing about $975 million in a joint venture to own natural gas pipelines and storage serving the northeast markets.
Stagecoach Gas Services will be managed by Crestwood Equity Partners and own assets in Pennsylvania and New York.
Con Ed announced the creation of Con Edison Transmission, a unit to invest in pipeline and transmission line projects, in January. Like other utilities, Con Ed is investing more in pipelines as electricity demand slows.
Although it cleared the 2016/17 MISO capacity auction, the Clinton nuclear station may not stay open after May 31, 2017, without some sort of subsidies, warned Exelon CEO Chris Crane.
“Without urgent action on the policy front, we will have no choice but to prepare for a potential early retirement in the face of continued financial losses at our Clinton nuclear plant,” he said. “The loss of this plant would have significant economic impacts on southern Illinois and erase the environmental benefits equal to 80% of the wind installed in Illinois, making it significantly harder and more expensive for the state to meet its carbon reduction goals.”
Exelon is in the middle of a hard lobbying campaign in Illinois, seeking policy changes that would reward Clinton, and its five other nuclear stations in Illinois, for being carbon-free.
SunEdison’s Rise in Solar Industry Ends in Bankruptcy
SunEdison, the St. Louis-based company that shot to the top of American solar energy companies, filed for bankruptcy protection last week after multiple acquisitions left the company strapped for cash.
Analysts say the cause of the company’s demise stems from unwise investments, not an inherent problem with the solar industry. Much of the company’s growth occurred through a rapid series of large acquisitions, encumbering itself with substantial debt.
“Our decision to initiate a court-supervised restructuring was a difficult but important step to address our immediate liquidity issues,” CEO Ahmad Chatila said.
GridLiance Adds Seattle CFO To its Leadership Team
Bishop
GridLiance last week announced it had hired Seattle City Light CFO Jeff Bishop as its senior vice president, CFO and treasurer.
Bishop has spent 15 years in the industry, including financial leadership roles at PacifiCorp. He holds two bachelor’s degrees: one in accounting from Washington State University and another in zoology from the University of Washington.
“Municipal and consumer-owned power agencies, which have historically been unable to invest in large-scale, regional transmission projects, will benefit from GridLiance’s forward-thinking approach,” Bishop said.
Clearwater Energy is laying the groundwork for a 300-MW wind farm in eastern Montana, near transmission infrastructure that now serves the coal-fired Colstrip Power Plant near Billings.
The 500-kV power lines and a substation are big enough to accommodate Colstrip and the 300-MW Clearwater project. The Bonneville Power Administration, NorthWestern Energy and other stakeholders in the transmission lines serving Colstrip have discussed upgrading the transmission system to 700 MW. The Clearwater project is being planned to fill that extra capacity if it materializes.
Eversource Energy has named the contractors and material suppliers for the $1.6 billion Northern Pass transmission line, which is awaiting final state and federal permits.
Eversource named Quanta Service subsidiary PAR Electrical Contractors as general contractor. Burns and McDonnell Engineering will continue as part of the project team. The ABB Group will design and build the line’s underground section and a converter station in Franklin, N.H.
PPL Electric Utilities last week completed its $350 million Northeast-Pocono Reliability Project — more than a year before its original target date.
The 60-mile 230-kV line, which includes three new substations, should mean fewer and shorter outages for customers in Pennsylvania’s Lackawanna, Monroe, Wayne, Pike
and Luzerne counties, the company said. It’s the second major transmission project completed by PPL in the past year, following the $648 million Susquehanna-Roseland line, which was completed in May 2015.
While construction on Northeast-Pocono is complete, the company said land restoration will continue through the end of the year.
FERC told NYISO last week that proposed changes to its rules for reliability-must-run generators are insufficient, ordering another compliance filing in 60 days.
Cayuga Plant Source: Wikipedia
In February 2015, the commission found NYISO’s Tariff unjust and unreasonable because it lacked rules governing the retention and compensation of generating units needed for reliability. FERC took action after several coal-fired and nuclear generators in western New York announced their closures and the ISO was unable over nearly four years to win stakeholder consensus regarding uniform compensation rules for RMR units. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)
On Thursday, the commission said the ISO’s revised rules complied only in part with its directive (ER16-120, EL 15-37).
The commission approved the ISO’s use of going-forward costs as a compensation mechanism for generators and its use of net present value to compare solutions to reliability concerns. But it rejected the ISO’s proposed role for the New York Public Service Commission, its cost allocation proposal and its plan for bidding RMR generators into capacity auctions.
‘Gap Solution’
NYISO proposed adding its RMR rules to its existing “gap solution” process. The gap solution is currently triggered when the ISO’s biennial reliability planning process determines that neither market-based nor regulated proposals will address a reliability need quickly enough, or if its Board of Directors — after consulting with state regulators — determines there is an imminent reliability threat.
Under the ISO’s proposal, it would solicit gap solution — generation, transmission or demand response — and market-based solution proposals when it identifies a reliability need that would result from a generator deactivation.
If there are no viable market-based solutions, the ISO would provide the PSC with a list of transmission and DR gap proposals. The ISO would enter into an RMR agreement only if there are no viable non-generation solutions or if the PSC does not select such a solution from the list provided by the ISO.
FERC said the ISO’s plan was inconsistent with Order 1000, improperly delegated authority to the PSC and could lead to inefficient transmission development.
The commission also rejected a proposal that generators provide 365 days’ notice before deactivation, more than doubling the 180 days required by the PSC. Generators had protested that the proposed notice period was “unreasonably long.”
FERC did not rule on the merits of the extended time frame but said it would address the timing issue after NYISO proposes Tariff amendments outside of the gap solution process. The commission further said it could not determine whether a generator should be compensated during the notice period and at what level.
Capacity Pricing
FERC also rejected the ISO’s proposed cost allocation for RMR generators and transmission gap solutions as inconsistent with Order 1000 and its plan to bid RMR generators into its capacity auction at prices above $0/kW-month. “It is more efficient for RMR generators to offer their [unforced capacity] at $0.00/kW-month as ‘price-takers,’” FERC said.
It accepted in part the ISO’s provisions to prevent generators from “toggling” between RMR compensation and market-based rates, requiring additional protections.
WASHINGTON — A May 13 FERC technical conference reviewing generator interconnection procedures will include a discussion on the interconnection of energy storage resources (RM16-12, RM15-12).
The tech conference was scheduled in response to a 2015 petition by the American Wind Energy Association to revise the commission’s pro forma large generator interconnection agreement. Other topics to be discussed include the current status of interconnection queues and transparency in the interconnection study process.
The conference was brought up by FERC Chairman Norman Bay during a presentation staff gave the commission at its open meeting last week on the data requests it sent six grid operators regarding their rules for energy storage participation in the wholesale markets. The storage issues slated for discussion at the conference are largely the same as those the RTOs will address in their responses to the data requests, which are due May 2. (See FERC to Examine RTO Roles for Energy Storage.)
“Energy storage is one of the big potential game changers in the energy industry,” Commissioner Tony Clark said. “This line of inquiry that we’re opening and the responses we’re going to get back I think are going to be tremendously important.”
National Labs Brief FERC on Grid Modernization
Representatives from the Department of Energy and its national laboratories said that increased communication and cooperation with FERC will be needed in order to help them in their efforts to modernize the grid.
These efforts — including integrating renewable energy resources and energy storage, and increasing protection against cyber threats — were detailed in a series of presentations at the commission’s open meeting last week. The integration of new technologies will result in a paradigm shift in how energy is generated and used, they said.
One of “the key trends and themes that we’re reinforcing is the evolution towards more distributed control,” said Jeff Dagle, chief electrical engineer at Pacific Northwest National Laboratory. “Historically, we’ve forecasted demand and dispatched supply. I think increasingly in the future, we’ll be forecasting supply and dispatching demand.”
Chuck Goldman, of the Lawrence Berkley National Laboratory, urged FERC to consider having its senior staff participate in the advisory committees on some of the labs’ projects. He also said the commission should “think about the kinds of [research and development] that might be appropriate for ISOs that’s in the public interest [and] that can deal with grid modernization issues.”
FERC last week accepted revisions to SPP’s joint operating agreement with Western Area Power Administration-Upper Great Plains Region (WAPA-UGP), denying rehearing and clarification requests by MISO and 23 of its transmission owners (EL12-60, ER12-1586).
The commission’s April 21 order granted SPP and the Integrated System’s request for clarification that the term “energy exchange” reflects their intent that the JOA does not affect the transmission rights or service of third parties.
MISO and its TOs had protested FERC’s September 2012 order accepting the JOA, which was filed in April 2012 as a precursor to the IS’ membership in SPP. They said part of the JOA would be “incompatible” with market-to-market coordination between MISO and SPP when the latter’s Integrated Marketplace began operating, and that the agreement equated to “assessing compensation for loop flow.”
FERC rejected both arguments. The IS, comprising WAPA-UGP, Basin Electric Power Cooperative and Heartland Consumers Power District, became full transmission-owning members of SPP in October.
The commission clarified that that sections 5.4-5.6 of the JOA are the parties’ method for addressing contract path capacity determinations. The commission affirmed its prior determination that the language does not violate market-to-market principles or constitute unauthorized loop flow compensation.
“As the commission stated elsewhere in the Sept. 18 order, sections 5.4-5.6 of the [WAPA-SPP] JOA do not govern loop flow; rather, loop flow is governed by the congestion management process.”
New York utilities and three solar companies on Tuesday proposed a business model that they said would replace net metering and address cost-shifting concerns, a pact that could serve as a model nationally (15-E-0751).
The proposal was made in a proceeding of New York’s Reforming the Energy Vision initiative.
The Solar Progress Partnership includes Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, National Grid, Orange and Rockland Utilities, Rochester Gas and Electric and the solar companies SolarCity, SunEdison and SunPower.
“At its core, the partnership’s proposal provides simplicity for customers, recognizes the locational value of clean [distributed energy resources] and attempts to resolve potential bill impacts, particularly to customers who are not participating in [net metering],” the filing states.
Under net metering, utilities pay for surplus power from rooftop solar systems. Utilities say this means ratepayers without solar systems are paying more than their share of grid costs. (In the Orange and Rockland service territory, customers are reimbursed at the NYISO day-ahead hourly price, which is the wholesale rate. Some other utilities pay at the retail rate.)
The proposal would preserve credits for residential rooftop solar systems. But it proposes a transition from the current net metering model that would begin in 2020 for larger projects. The filing recommends collecting a payment from solar developers for community and remote solar projects connected to the grid.
The proposal marks a potential cease-fire in the battles solar developers have fought with utilities in states across the country. In December, SolarCity announced it was ending operations in Nevada after regulators cut payments to rooftop panel owners.
News of the agreement appeared to cheer investors. SolarCity shares ended last week at $33.34, up 9% from the open Tuesday, while SunPower shares were up less than 1% at $21.66. SunEdison shares were trading at $0.34 Thursday — when the company announced it was seeking Chapter 11 bankruptcy protection — up 6% from Tuesday.
“We’re working together to keep our state’s solar market vibrant while enabling us to maintain the robust power grid that solar energy requires, and in a way that is fair to all customers,” Con Edison CEO John McAvoy said in a joint statement.
SolarCity CEO Lyndon Rive also was conciliatory. “The deep institutional knowledge of these six utilities and the creative approach they are taking to the evolution of electricity is inspiring. Leaders like these will lay the foundation for the grid of the future.”
The proposal said it would use elements of a New York Public Service Commission staff white paper to transition to a compensation structure “that more closely aligns with the value the resources bring to the power system, including the wholesale power system (‘LMP’), the electric distribution system (‘D’) and to society at large (‘E’), which is generally the environmental benefit.”
Each community distributed generation (CDG) project would be assigned to a tranche that would establish a compensation rate and developer payments. “Each successive tranche would incorporate higher developer payments, gradually moving the total resource compensation rate to LMP+D+E,” the partnership said.
According to PSC data, the state has more than 3,100 MW net energy metering resources installed or in utilities’ interconnection queues. “These queues have more than doubled in the first three months of 2016,” the proposal said. “Much of this recent development activity has been configured as CDG projects.”
Barriers to Entry?
The plan would require developers to provide letters of credit, a condition that Karl Rábago, head of the Pace Energy and Climate Center, said bars small developers.
“In the early days of the Texas market deregulation, that’s really what shook out the smaller developers,” Rábago, a former Texas Public Utility Commissioner toldCapital New York. “I don’t have a line of credit if I’m a small player.”
AUSTIN, Texas — ERCOT’s Independent Market Monitor said last week that negative prices are becoming less frequent and that they have virtually no impact on average energy prices, despite media attention given to them.
Steve Reedy, the IMM’s deputy director, told the Board of Directors during his regular update that while negative prices “are not a problem, they’re certainly something as an economist that interest me.”
Reedy said the Monitor saw “significant amounts” of negative pricing in ERCOT’s West zone — where most of the ISO’s 15,764 MW of wind capacity resides — during the first year of the nodal market, which went live in 2010. The completion of the $6.8 billion, 3,600-mile Competitive Renewable Energy Zone (CREZ) transmission buildout in February 2014 resolved most of the congestion issues.
“For the most part, we’ve seen [those prices] go away,” Reedy said. “We still have negative prices, but rather than being the norm early in the nodal market and in the zonal market, it’s now the exception.”
Reedy expressed mild frustration that a September Slatearticle detailing prices reaching as low as -$8.52/MWh led to a flurry of additional press coverage. He said the Sept. 13 event was typical of wind energy being offered into the market at off-peak hours.
Testing his hypothesis, Reedy asked Monitor staff to calculate negative prices’ effect on the ERCOT market by replacing every negative price with a zero.
The end result? An energy-weighted price of $26.78/MWh for 2015, virtually identical to the $26.77 average including the negative prices.
“It’s a late-night, early-morning phenomenon. It’s not an example of the CREZ being used up,” Reedy said. “It’s driven a lot of press, but it’s not had a major effect on the price.”
Texas Public Utility Commissioner Ken Anderson asked whether ERCOT would be seeing the same behavior without the federal production tax credit, which is worth $23/MWh. “No, I don’t think that would be the case without the PTC,” Reedy told the commissioner.
“We’ve seen over the last five years that the west export capacity, due to CREZ, has expanded significantly,” he said. “Even with the growth of wind energy, we rarely get that crossover where [we end up with negative prices].”
Asked what was causing the low-priced energy, Reedy could only reply with anecdotal evidence, suggesting that some coal generators might be running overnight to reduce their fuel stockpiles, and that other market participants might be running units overnight to eliminate start-up risks.
Reedy also discussed the operating reserve demand curve (ORDC), a price adder created to reflect the value of reserves during high-load periods. ERCOT staff compiled stakeholder proposals for revising the ORDC in a white paper earlier this year, following Anderson’s call for a PUC review of it and its methodology. (See “State Regulators Seeking Answers to Summer Incident,” ERCOT: No Consensus on Operating Reserve Changes.)
Texas regulators are considering whether to artificially raise wholesale power prices, as ERCOT is seeing prices at 14-year lows. The PUCT met April 14 to consider the issue and will again discuss the topic May 4. Commission staff has issued a memo summarizing comments it has received from market participants.
[Editor’s Note: An earlier version of this article stated incorrectly that the white paper contained ERCOT staff’s recommended changes to the ORDC.]
Board Easily Passes LOC Revision
The board approved the Technical Advisory Committee’s recommended parameters for payments of lost opportunity costs to generators ordered to ramp down for grid reliability, with just two opposing votes and no discussion.
“No questions?” board Chair Craven Crowell asked the members, surveying the room. Addressing TAC Chair Randa Stephenson, he said, “Sounds like you did a good job on it then.”
“We worked hard,” Stephenson responded.
The board had remanded Nodal Protocol Revision Request (NPRR) 649 back to the TAC at its February meeting. Last month, the committee was able to reach agreement on one of three options, amending the language to reflect comments it received from the board. (See ERCOT Stakeholders Agree on Lost Opportunity Costs Rule.)
The Texas Office of Public Utility Counsel’s Tonya Baer (Residential Consumers) and the City of Dallas’ Nick Fehrenbach (Commercial Consumers) cast the two negative votes.
Stephenson, of the Lower Colorado River Authority, said the request’s original impact analysis of $100,000 to $150,000 had been reduced to the $50,000-$75,000 range, assuming high-dispatch limit (HDL) overrides remain at current levels. She said ERCOT has revised its procedures since Odessa-Ector Power Partners claimed its combined cycle plant had lost $300,000 because of three days of HDL overrides in November 2012 and only one HDL since last May.
“We anticipate costs to the load … when this does occur [again], it will be an uplift,” Stephenson said. She said the TAC will continue to monitor and report back on any uplifts.
The board also approved NPRR 745, which changes the emergency response service’s availability from an hourly to 15-minute interval evaluation and makes other minor changes.
ERCOT CEO Bill Magness told the board that 2016’s net revenues are $1.8 million above expected, despite system administration fees being $1.7 million under budget due to mild weather conditions. Timing differences kept spending $3.1 million under budget, he said in his report.
Pointing to an overhead screen filled with maps of Texas, Magness said, “That’s five different ways up there of saying it’s warm. The basic story is, we did have a pretty warm, pretty dry winter.”
Magness also reported that staff is testing an upgrade to ERCOT’s energy management system, which could go live as early as May 26. He noted the EMS is just one of several software systems scheduled to go live this year.
The CEO also mentioned ERCOT’s creation of the Grid Resilience Working Group, which will assess low-probability but “potentially high-impact” risks to the ISO’s system. Its first meeting is scheduled for April 26.
Bermudez, NPRRs Approved
The board re-elected unaffiliated Director Jorge Bermudez to a third and final term. His second term expires in June.
It also unanimously approved seven NPRRs and one change-request on its consent agenda:
NPRR 741: Clarifications to estimated aggregate liability (EAL) and total potential exposure (TPE) credit exposure calculations.
NPRR744: Reliability unit commitment trigger for the reliability deployment price adder and alignment with RUC settlement.
NPRR 748: Revisions associated with NERC reliability standard COM-002-4 and other clarifications associated with dispatch instructions.
NPRR 749: Requires ERCOT to publish the cost of options for all outstanding congestion revenue rights within the CRR auction process.
NPRR 750: Clarifies the practice for setting telemetry when providing fast-responding regulation service.
SCR 787: Changes the net-dependable capability and reactive capability (NDCRC) application to provide historical generator information to all associated resource entities.
FERC approved an uncontested partial settlement between Northern Indiana Public Service Co. and the owners of seven Indiana wind farms that contend the utility overcharged them for transmission upgrades.
Meadow Lake Wind Farm Source: Meadow Lake Wind Farm
The April 21 order (EL14-66-003) resolves issues related to NIPSCO’s 138-kV transmission upgrade funded by the Meadow Lake and Fowler Ridge wind farms. Under the settlement, the utility will pay $400,000 to Meadow Lake and $450,000 to Fowler Ridge to withdraw their complaint.
E.ON Climate & Renewables North America filed the original complaint against NIPSCO in 2014, objecting to the multiplier rate used in two transmission upgrade agreements with its Pioneer Trail and Settlers Trail wind farms. FERC later that year ruled that the multiplier was unreasonable and instructed the two companies to enter into settlement proceedings to determine a new rate (EL14-66).
Meadow Lake and Fowler Ridge filed a similar action after the ruling. NIPSCO charged their facilities and several other wind farms $35.8 million to cover 35 years of operating costs on top of the $50.4 million to build transmission. (See NIPSCO Blows Back at Wind Farm Complaints.)
FERC’s acceptance of the partial settlement also closes out Meadow Lake and Fowler Ridge’s request for rehearing in E.ON’s complaint (EL14-66-002).
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.”
The turbines were retired in staggered order in consultation with MISO. The turbines included two at B.C. Cobb, two at the D.E. Karn/J.C. Weadock Generating Complex in Essexville and three at the J.R. Whiting Generating Complex in Luna Pier.
Kentucky’s largest solar facility was inaugurated last week by Louisville Gas & Electric and Kentucky Utilities. The E.W. Brown Generation Station in central Kentucky contains about 44,600 solar panels, capable of producing 19,000 MWh of electricity annually.
Exelon Generation and Renewable Energy Systems are joining to build a 10-MW energy storage facility in Clinton County, Ohio, that is expected to be operational by the end of the year.
Consolidated Edison is investing about $975 million in a joint venture to own natural gas pipelines and storage serving the northeast markets.
Although it cleared the 2016/17 MISO capacity auction, the Clinton nuclear station may not stay open after May 31, 2017, without some sort of subsidies, warned Exelon CEO Chris Crane.
SunEdison, the St. Louis-based company that shot to the top of American solar energy companies, filed for bankruptcy protection last week after multiple acquisitions left the company strapped for cash.
The commission’s April 21 order granted SPP and the Integrated System’s request for clarification that the term “energy exchange” reflects their intent that the JOA does not affect the transmission rights or service of third parties.
NIPSCO, which operates on the seams of the RTOs, 
