Coal’s share of SPP’s energy production continues to slide in the face of low gas prices and increased wind generation, according to the RTO’s latest State of the Market report.
The SPP Market Monitoring Unit’s spring report says coal-fired generation accounted for just 41% of the RTO’s energy production between March and May, its lowest percentage ever and a stunning 31% drop from spring 2014, when coal resources provided 59% of the RTO’s energy. Coal generation accounted for more than 65% of total generation in 2007, SPP’s first year as an organized market.
Coal’s diminished market share is largely attributed to the continuing drop in gas prices. Prices at the Panhandle Hub have dropped 64% since spring 2014, from $4.66/MMBtu to $1.68/MMBtu, and 32% since spring 2015, when the price was $2.46/MMBtu.
That contributed to average real-time LMPs of $17.37/MWh (compared to $34.72/MWh in 2014) and day-ahead LMPs of $17.07/MWh (versus $37.03/MWh in 2014). The Monitor said it is the first time since the Integrated Marketplace opened in March 2014 that day-ahead prices were below real-time.
Coal-fired resources were also backed down by the ready availability of wind energy, which accounted for 21.5% of all energy produced this spring, compared to 15% last year. SPP’s wind penetration has risen from the 30% range to a new high of 49.17% of total generation this year.
The Monitor also said cleared virtual transactions are approaching the levels of other RTOs, at about 10% of reported load. It said gross virtual profits for the Integrated Marketplace’s most recent 12 months totaled nearly $78 million, with gross virtual losses totaling nearly $58 million.
Virtual trades have shown net profits every month since the Integrated Marketplace began, with the exception of May 2014.
The Public Utility Commission of Texas said it will invite stakeholder comments as it takes a cautious approach to Lubbock Power & Light’s planned integration into the ERCOT grid.
“I think this is an incredibly complicated situation. I’m not sure it’s even clear how … we evaluate it,” PUC Chair Donna Nelson said during the commission’s June 29 open meeting. “I do have concerns about the FERC jurisdiction aspect of it … I’m concerned about [Lubbock] having generation that flows outside of Texas.”
“We need to be mindful of the precedent it sets,” Commissioner Ken Anderson agreed. “I believe there might be other entities in Texas — other regions, groups — that look with envy on ERCOT, and for good reason.”
LP&L announced last September it planned to disconnect from SPP and join ERCOT by 2019. Xcel Energy, whose Southwestern Public Service subsidiary serves LP&L’s load, asked FERC in May for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan. (See Xcel Asks for $88.7M Fee for Lubbock Switch to ERCOT.)
Nelson, Anderson and Commissioner Brandy Marty Marquez all said they would like to see LP&L’s integration turned into two separate cases, one involving the move from SPP’s grid to ERCOT’s, and the other involving a cost-benefit analysis of the transfer on ratepayers. Nelson said she would issue a memo outlining the parameters on further studies before the PUC’s next open meeting July 20 (Docket No. 45633).
An ERCOT study completed in June indicated it would cost $364 million and take 141 miles of new 345-kV right of way to incorporate LP&L into ERCOT. (See “LP&L Integration Could Unlock More Panhandle Wind Energy,” ERCOT Board of Directors Briefs.)
The City of Lubbock has told the PUC it would prepare an impact analysis of the LP&L load that would migrate to ERCOT, using the Texas grid operator’s report as a starting point. It said its report will be “holistically framed around three key areas of study”: the effects on existing ERCOT stakeholders, on existing SPP stakeholders and on Lubbock customers.
“I think it’s appropriate to allow people to file responses to the ERCOT filing and to what Lubbock has filed,” Nelson said. “We have to make sure ERCOT [and] the ratepayers of Texas are treated fairly. I think SPP and the ratepayers in SPP should be treated fairly too.”
Marquez said one of her concerns is “what happens to the communities that are left behind, and what kind of rates do they absorb?”
Anderson said he wants more “clarity” from ERCOT on the available integration options, saying the ISO’s preferred option “seems to be predicated on the assumption that most of what they are recommending will be needed anyway.”
“If two years later we have to go back and approve what ERCOT recommended,” Anderson said, “by then, we may have way overpaid.”
The municipality has said it faces time constraints in meeting its 2019 timeline, but the commissioners said that wasn’t their primary concern.
“I’m not going to take on that responsibility,” Nelson said. “We need to avoid putting ourselves in a position where we’re there to rescue the day if people have put themselves in that position.”
“These are Texans, but these are Texans that didn’t want us,” Marquez said. The SPS region opted out of Texas’ competitive market before it opened in 2002.
Municipal utilities Austin Energy and CPS Energy of San Antonio, both ERCOT members, also opted out of competition.
The Public Utilities Commission of Ohio staff has proposed a new rider for FirstEnergy that would allow the recovery of $131 million annually from ratepayers for three to five years in order to maintain the company’s investment-grade credit rating.
“Staff believes the long-term financial health of FE will have benefits for the Ohio regulated distribution facilities, as well as the state of Ohio in general,” PUCO’s Joseph Buckley testified Wednesday (Case No. 14-1297-EL-SSO).
FirstEnergy’s Davis Besse Power Plant Source: Wikimedia
Buckley cited Moody’s Jan. 20 credit opinion saying that the company could receive a rating downgrade without an increase in revenues allowing it to generate cash flow from operations equal to at least 14% of its debt. He said staff believes that three years is enough time for FirstEnergy to address its finances, and that it could request an extension of the rider if necessary.
The Distribution Modernization Rider would require FirstEnergy to maintain its corporate headquarters and most of its operations in Akron or forego the credit. The agreement also would be terminated if the company or its subsidiaries were to undergo a change in ownership.
Critics of FirstEnergy’s attempts to win subsidies from Ohio regulators objected.
“While the staff frame their proposal in terms of grid modernization, the apparent absence of any requirement that FirstEnergy invest the money on modernizing the grid means that this new proposal is effectively just another corporate bailout,” Earthjustice, representing the Sierra Club, said in a statement.
Dick Munson of Environmental Defense Fund called it “an unnecessary subsidy.”
PUCO staff said last week that modified proposal should be rejected in favor of the recommended rider.
Doug Colafella, a spokesman for FirstEnergy, said Friday, “The filing of staff’s testimony is another step in the regulatory process. We will continue to work with the commission and other parties to achieve an outcome that will protect our customers and communities.”
On Thursday, FERC Chairman Norman Bay responded to a letter from U.S. Sen. Joseph Manchin (D-W.Va.) explaining the commission’s role in the dispute (EL16-33, EL16-34). Manchin, a staunch supporter of his state’s coal mining industry, had asked FERC on April 20 to “allow [Ohio’s] prudent action to stand.”
Great Plains Energy and Westar Energy filed a joint application with the Kansas Corporation Commission to approve the $12.2 billion sale of Westar to Great Plains.
The companies estimated pre-tax savings and efficiencies from the merger at about $65 million in the first year. The sale also is expected to generate $60 million in transaction costs through 2020. If approved, the transaction will close in spring 2017.
The deal is also subject to FERC approval, and the Missouri Public Service Commission is still evaluating whether it should have jurisdiction.
Wisconsin Co-op Using 4-Legged Vegetation Management System
The Eau Clair Energy Cooperative has hit upon an energy-saving, green method of controlling the vegetation at its solar farm in Fall Creek: sheep.
The co-op turned loose 15 three-month-old lambs to control the grass and weeds at the facility, the largest community solar facility in the state. “It’s all about sustainability,” Eau Clair spokeswoman Mary Kay Brevig said. “It’s kind of funny, they kind of stay in a group; they’re fairly timid.”
The co-op obtained the sheep from member Lambalot Acres. “They’ve got solar panels, which is a very green source of energy, and we’ve got sheep, which just eat the greens,” Dylan Klindworth of Lambalot Acres said.
DTE Energy has installed a natural gas-burning residential combined heat and power system at a Northern Michigan home, footing the $27,000 price tag in exchange for monitoring the unit for a year.
The PowerAire by Houston-based M-TriGen is a three-cylinder engine that produces 4 to 8 tons of thermal energy for heating, 2 to 10 tons of cooling capacity and 5 to 10 kW of electricity. Robert P. Fegan Jr., principal market technical consultant for DTE, said the unit can fully power the 3,200-square-foot house if needed.
DTE is performing viability tests on the unit, the first of its kind to be installed in Michigan. M-TriGen Vice President of Sales Randy Erwin said around 50 PowerAire units are in service in several states.
Korean Firm, Alliant Complete Wisconsin’s Largest Solar Plant
Alliant Energy has put Wisconsin’s largest solar installation, built on top of a coal-ash landfill, into service.
Korean solar energy firm Hanwha Q Cells built the 7,700-panel, 2.2-MW plant on Alliant’s landfill property near the Wisconsin-Illinois border. Alliant said it will purchase power from the project for the next 10 years and have an opportunity to purchase the $5 million installation after that.
The new solar plant is part of Alliant’s recent settlement with EPA over pollution from its coal-fired fleet.
PSEG’s Lopriore Retiring After 43 Years in Generation
Lopriore
Rich Lopriore, whose career in electricity generation has spanned more than four decades, is retiring as president of PSEG Fossil.
Lopriore came to Public Service Enterprise Group from Exelon during an aborted attempt at a merger between the two companies. He previously served as plant manager at Exelon Nuclear’s Byron Station and then senior vice president in charge of Mid Atlantic Operations for Exelon nuclear. He also worked at Duke Energy’s Brunswick Nuclear Plant.
Lopriore will retire to Massachusetts. A replacement has not been named.
Pipeline giant Energy Transfer Equity has called off its proposed acquisition of Williams Co., following a Delaware judge’s ruling that the transaction could be terminated. The deal was valued around $38 billion, including debt, when it was reached in September.
Dallas-based Energy Transfer has sought for months to kill the cash-and-stock deal following a sharp decline in the energy markets last year. Tulsa-based Williams and Energy Transfer had accused each other of breaching the terms of the agreement, and the deal’s value declined as a fall in oil prices hurt the financial prospects of their customers.
The fight over the deal may be far from over. Williams shareholders approved the transaction during a special meeting June 27, and the company filed papers to begin the appeal process in the Delaware Supreme Court.
GridLiance and the Kansas Power Pool announced a collaboration to improve the transmission infrastructure in KPP’s service area.
GridLiance’s South Central Region within SPP will work with KPP’s 31 member cities to jointly plan, construct and operate transmission infrastructure. GridLiance will also manage NERC compliance and assist KPP in navigating SPP’s processes, providing greater participation in transmission planning, rate determination and other key functions.
San Diego Gas and Electric is the first California investor-owned utility to meet its cap under the state’s original net energy metering (NEM) rule, which restricts projects eligible for net metering to 5% of a utility’s peak load.
The company will now shift future distributed energy customers to NEM 2.0, a revised rule issued earlier this year by the California Public Utilities Commission in anticipation of the continued rapid growth in rooftop solar.
The new rule requires continued compensation for customers who export energy to the grid while also subjecting them to an interconnection fee, time-of-use rates and new fees to support low-income and energy efficiency programs.
APS Elevates Company Veteran To Head Nuclear Operations
Bement
Arizona Public Service last week announced that Bob Bement has been appointed executive vice president for nuclear operations at the utility’s Palo Verde nuclear generating station.
Bement will take over as chief nuclear officer on Oct. 31, replacing Randy Edington, who will assume a role as an adviser to company CEO Don Brandt.
Bement has overseen nuclear operations at the plant since 2007, having previously held senior positions with Exelon and Arkansas Nuclear One.
Oklahoma Gas and Electric implemented a $69.5 million interim rate increase last week as it awaits a decision from the Oklahoma Corporation Commission in its rate case.
OG&E filed for a $92.5 million rate increase in December. An administrative law judge heard arguments in hearings that ended in May. Oklahoma law allows utilities to establish interim rates if the three-member OCC hasn’t issued a final order within 180 days.
The utility said the increase, subject to refund, would be offset by a lowering of the fuel-adjustment charges that it is required to pass along to consumers.
The Indiana Utility Regulatory Commission on Wednesday accepted a settlement negotiated between Duke Energy and local consumer groups on a statewide infrastructure upgrade plan.
The seven-year, $1.4 billion plan results in an average 0.93% increase in Duke Energy Indiana customer rates annually over the next seven years. Individually, the year-long increases range from 0.58% to 1.35% until 2023.
The IURC found that “public convenience and necessity require” Duke’s planned transmission, distribution and storage improvements.
The settlement was reached in March among the Indiana Office of Utility Consumer Counselor, Duke Energy Indiana, steelmaker Companhia Siderurgica Nacional, Steel Dynamics, Wabash Valley Power Association, Indiana Municipal Power Agency, Hoosier Energy Rural Electric Cooperative and the Environmental Defense Fund.
“We are happy with the settlement,” said Anthony Swinger, director of external affairs for the IOUCC. “We believe the settlement strikes the right balance between ratepayer protection and the utilities’ need to make infrastructure improvements in order to provide safe, dependable service.”
“We have an aging energy grid — some equipment that is decades old — and our work will focus on replacing some older infrastructure to reduce power outages,” Duke Energy Indiana President Melody Birmingham-Byrd said. “We’ll also be building a smarter energy structure with technology to provide the type of information and services that consumers have come to expect.”
Duke plans to invest in line sensors and “self-healing” systems, as well as replace aging substations, utility poles, power lines and transformers.
A little over a year ago, the IURC denied Duke Energy Indiana’s original proposal, causing the utility to trim $400 million from the plan, including the elimination of a $192 million project to install smart meters. The company now says that if it pursues smart meters using the settlement, it is “committed to exploring energy efficiency pilot programs that are now possible with smart meter technology.”
The New York Green Bank wants to increase its portfolio by two-thirds over the next year, mostly by investing in larger clean energy projects.
In its annual business plan released last week, the state’s clean energy investment arm said it wants to invest $200 million, or $50 million per quarter, in projects that otherwise might not attract enough private capital on their own.
The bank invested $120.5 million in nine transactions over the past year, which was leveraged into a project portfolio valued at $518.3 million. These commitments are expected to result in 128 MW of new capacity.
The Green Bank is administered by the New York State Energy and Research Development Authority as part of the state’s $5.3 billion Clean Energy Fund. (See NYPSC OKs $5.3B Clean Energy Fund.) The bank has a short-term goal of deploying private capital at a rate of 3-to-1 above its own funds, with a longer-term goal of an 8-to-1 ratio when the fund ends in 2025.
The bank is seen as a way to jump-start projects to achieve New York’s goal of obtaining 50% of its energy from clean sources by 2030.
So far, the bank has received $220 million from the state. Now it wants to scale up the project pipeline.
“NYGB has identified two potential opportunities to accelerate market transformation via the creation and introduction of targeted financial products. In both cases, the market is potentially large, but currently suffers from fragmentation, lack of standardization and lack of scale,” the plan says.
Based on input submitted by project developers, financiers and other stakeholders in response to a recent request for information, the Green Bank expects to issue two requests for proposals. Its new targets are commercial real estate and multi-family solar and/or energy efficiency systems that would be owned by the building owner instead of third parties, and ground-mounted solar systems for corporate or industrial end users.
On the same day the business plan was released, the Green Bank closed a $25 million loan for residential solar installer Sunrun. The loan is intended to accelerate construction of more than 5,000 solar projects across the state. It comes on the heels of a separate $25 million loan from the Green Bank in May that was part of a $340 million credit facility Sunrun executed over the past several months.
The bank has been capitalized at $1 billion with support from ratepayer funds and New York’s proceeds from its participation in the Regional Greenhouse Gas Initiative. It has a goal of becoming self-sustaining by 2018 through returns from its project portfolio. (See Project Interest Overwhelms New York’s Green Bank.)
ERCOT’s Technical Advisory Committee canceled its scheduled June 30 meeting but held an email vote to unanimously approve a nodal operating guide revision request removing references to the provision of responsive reserves across DC ties.
The operating guides have included the references to responsive reserves — operating reserves ERCOT maintains to restore system frequency within the first few minutes of an event that causes a significant deviation — since at least 1997. Staff said there are no systems or procedures in place to award ancillary services to the DC ties, and no project to add this functionality has ever been proposed.
Staff said that without any funding for the necessary system changes, ERCOT has no mechanism for allowing the provision of responsive reserves over the DC ties.
FERC pushed back the timeline for an environmental impact statement on the Mountain Valley Pipeline, delaying construction of the $3.5 billion shale gas pipeline crossing Virginia for at least six months.
The developers of the 301-mile pipeline project applied for the environmental certificate in October, but FERC staff has repeatedly asked for more information, and now it says the EIS won’t be ready until March. The commission has 90 days after that to decide whether or not to issue final permits. That means construction is more likely to get underway in June of next year, rather than December 2016.
Congresswoman to Propose Stiffer FERC Pipeline Reviews
Coleman
In a move applauded by pipeline foes, U.S. Rep. Bonnie Watson Coleman (D-N.J.) said she will introduce a bill in the House requiring FERC regulators to be more critical when reviewing proposed pipelines.
Her proposal will introduce stiffer environmental reviews of pipeline projects and require them to explore “less environmentally disruptive alternatives.”
Coleman is wading into controversy surrounding the PennEast Pipeline, a project that would deliver shale gas from Pennsylvania primarily to New Jersey utilities. Opponents have cited PennEast an example of lax FERC review. The 119-mile, $1.2 billion pipeline is currently under review by FERC, but opponents said the commission is allowing PennEast to use routing and construction methods that are harmful to the environment.
Monthly Coal Generation Falls To Lowest Level Since 1978
The Energy Information Administration reported that coal use for electric power generation in April fell to its lowest level since 1978, while natural gas was the top fuel for the third straight month.
Plants fueled by coal generated 72.2 million MWh in April, the lowest since 1978. Natural gas-fired plants produced 100 million MWh in April.
Gas accounted for 34% of total generation in April, while coal came in at 31%, nuclear at 20% and renewables at 7%. Ten years ago, coal-fired plants produced 50% of the nation’s electricity and natural gas only 19%.
The newly expanded Panama Canal locks will be able to handle 90% of the world’s LNG tankers, reducing shipping time and expense for shipments to Asia from Gulf Coast terminals, according to the Energy Information Administration.
Before Panama opened the widened canal last month, the waterway could only accommodate 30 smaller LNG tankers, representing about 6% of the global fleet of tankers equipped to handle the super-cooled fuel.
The widened canal means it will take 20 days for shipments to reach Asian markets from Gulf Coast terminals, compared to the 34 days previously when large vessels to Asia were required to round Cape Hope or transit through the Suez Canal.
Having completed his second term at the end of June, Nuclear Regulatory Commissioner William Ostendorff is leaving the commission to teach at the U.S. Naval Academy in Annapolis.
Ostendorff, former director of the commission’s Committee on Science, Engineering and Public Policy, was first named to the commission in 2010. He began his second term in 2011.
Ostendorff’s departure creates a second vacancy on the five-member commission. Allison M. Macfarlane resigned as chair in December 2014, and that slot has remained open. President Obama nominated Jessie Roberson, a Democrat who serves as vice chairman of the Defense Nuclear Facilities Safety Board, a year ago. Senate Environmental and Public Works Chairman James Inhofe (R-Okla.) said in April he wanted to wait until Obama nominated a Republican so both vacancies can be filled at the same time.
Interior Changes Rules on Federal Coal Lease Payments
Jewell
The Interior Department will change the rules on how it collects royalties on coal mined on federal land to more accurately reflect its market value.
The rule change eliminates a loophole that allowed mining companies to pay royalties calculated on the price they charged their own subsidiaries, which often resold the coal at higher prices to end users. Coal mined from federal lands accounts for 44% of all coal mined in the U.S and generates about $1 billion annually in royalty revenue, but critics said that is artificially low.
“These improvements were long overdue and urgently needed to better align our regulatory framework with a 21st century energy marketplace,” Secretary of the Interior Sally Jewell said. The new rules take effect Jan. 1.
Senate Committee Approves $500 Million for Climate Fund
Merkley
The Senate Appropriations Committee approved $500 million for a fund that provides money for poor nations to combat climate change, a reversal of an earlier proposal that blocked the State Department from spending any money on the program.
The committee approved the funding through an amendment that removes language from the bill authorizing the State Department’s budget. The Obama administration had promised $3 billion for the program, called the Green Climate Fund, by 2020.
“We know we can’t take on this challenge by ourselves, so it’s part of the partnership in global leadership to address this … global issue,” said Sen. Jeff Merkley (D-Ore.), who led the effort to approve the amendment. “This is a real effort in bipartisan cooperation to present this amendment before the committee.”
ND PSC Commissioner Kalk Named to National Coal Council
Kalk
North Dakota Public Service Commissioner Brian P. Kalk has been named to the National Coal Council by U.S. Secretary of Energy Ernest Moniz. The council provides the secretary with advice on policy on coal and the coal industry.
“It’s important to remember that while renewable energy presents unique opportunities, coal is a strategic resource that heats millions of homes and provides low-cost reliable power,” Kalk said. “If the United States hopes to have true energy security, coal must be in the resource mix.”
The 6th U.S. Circuit Court of Appeals, rejecting a Sierra Club challenge, has ruled that an Enbridge oil pipeline that crosses a national forest in Michigan doesn’t need a new permit to keep operating.
The Sierra Club sued the U.S. Forest Service, saying it should have required Enbridge to prepare an environmental analysis before renewing the company’s right-of-way permit for Line 5. The 30-inch pipeline starts in Wisconsin and ends in Canada.
The court determined that there was nothing that required a new look at the pipeline, which runs through the Huron-Manistee National Forest.
TVA Aims to Cut 3,500 Jobs Through Voluntary Reductions
A month after the Tennessee Valley Authority celebrated the start-up of its new Watts Bar 2 nuclear reactor, it has announced plans to offer 3,500 nuclear staff members the option to voluntarily leave.
Employees at four locations — the Brown’s Ferry, Sequoya and Watts Bar nuclear stations and the nuclear services group in Chattanooga — have between July 11 and 29 to apply. Anyone who has been with the nuclear unit for at least a year can apply.
TVA said the workforce reductions are just the latest step in its ongoing effort to cut operation and maintenance costs, which has led to reducing 2,000 positions across all business units in the past three years. “This is a continuation of TVA’s efforts to ensure we have the right number of people for the roles we currently have,” a spokesman said.
Members Prepped for Problem Statement on Settlement Intervals, Shortage Pricing
WILMINGTON, Del. — The PJM Markets and Reliability Committee will be asked to approve a problem statement on first read next month regarding rule changes to comply with FERC Order 825, which requires RTOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period.
PJM has until Jan. 17 to file its compliance with the June 16 order, PJM’s Adam Keech said. After that, the RTO has four months to implement shortage pricing provisions and 12 months for settlement provisions.
While FERC did not order the changes be implemented simultaneously, members may consider requesting coincident start dates because the issues are related, he said. (See FERC Issues 1st RTO Price Formation Reforms.)
Charter for Underperformance Risk Management Senior Task Force Presented
Members heard the first reading of a draft charter for the Underperformance Risk Management Senior Task Force. The committee will be asked for its approval at the July meeting.
The charter reflects two separate issue charges. The first, managing the risk of underperformance under Capacity Performance, was approved in December. (See “Ways to Mitigate Risk in CP Market to be Studied,” PJM Markets and Reliability Committee Briefs.) The task force will seek to develop ways that CP resources can manage their risk during performance assessment hours.
The second, concerning external CP enhancements, passed in May. (See MRC Approves Charter for Seasonal Capacity Effort.) The group will seek to better align the requirements for internal and external resources.
PJM’s Rebecca Carroll said the task force is looking to implement changes for the 2020/21 Base Residual Auction next May. The task force expects to return to the MRC with recommendations by September.
On a related issue, CEO Andy Ott urged the Seasonal Capacity Resource Senior Task Force to be realistic about changes to allow seasonal resources to participate in CP. In particular, he discouraged them from moving to a seasonal product from an annual one.
“We need to work on aggregation, work on verification standards,” he said. “But to try to completely revamp the definitions would distract from the goal of trying to make change that is attainable,” he said.
More Flexible PLS Process Approved
The MRC approved a proposal to make the parameter-limited schedule exception process more flexible.
With the change, generators can request exceptions after the Feb. 28 deadline. They also will be permitted to seek extensions of a temporary exception (to a period or persistent exception) after that date.
It also gives PJM and the Independent Market Monitor more time to review requests and respond to market sellers. (See “More Flexible Parameter Limited Exception Process Approved,” PJM Market Implementation Committee Briefs.)
PJM Delays Endorsement of Manual Changes
PJM delayed an endorsement vote on two manual changes in response to members who wanted more time to discuss the issues.
Regarding Manual 14C: Generation and Transmission Interconnection Facility Construction, the tie line issue will be lifted out and returned to the Planning Committee for discussion, PJM’s Jason Shoemaker said. The changes were sought to support the inclusion of Order 1000 processes.
As for proposed revisions to Manual 15: Cost Development Guidelines, PJM delayed asking for endorsement to give members more time to discuss aspects related to the fuel cost policy approval process. The issue is expected to return to the Market Implementation Committee next month before being presented again to the MRC.
Manual Changes
Members unanimously endorsed the following manual changes:
Manual 7: Protection Standards. Clarifications were recommended by the Relay Subcommittee as part of its biennial review of the manual.
Manual 10: Pre-Scheduling Operations. Changes make clear that outage reporting rules apply to both capacity and energy resources.
Manual 14B: PJM Region Transmission Planning Process. Updates light load and winter peak reliability analyses to align with current practices, among other updates.
Manual 18: PJM Capacity Market. Changes are the result of a periodic review; conforming changes relate to Capacity Performance and the “deploy all resources” action.
Members Committee Adopts Project Queue Submittal Changes, Elects Finance Committee Member
The Members Committee approved Tariff revisions requiring earlier submittal of documentation in order for projects to secure a place in the interconnection queue.
Applications that have not cleared deficiencies by the close of the queue window will be terminated and withdrawn.
The committee also elected Gary Greiner of Public Service Enterprise Group to the Finance Committee. He will take the place of Frank Czigler, who retired from PSEG.
FERC on Thursday rejected CAISO’s proposal to prohibit Energy Imbalance Market participants from implementing economic bidding at the market’s external interties until the ISO can develop “appropriate rules and procedures” to manage the transactions (ER16-1518).
The ISO’s Tariff currently stipulates that each balancing authority area (BAA) that joins the EIM can determine for itself whether to allow resources located outside the market to submit economic bids at the BAA’s transmission seams.
CAISO sought to change its Tariff in part because EIM participants PacifiCorp and NV Energy had expressed concerns that implementing the practice would add complexity to their initial participation in the market.
The ISO cited another reason for the change: “The CAISO’s experience with 15-minute bidding at its own interties suggests that the extent of the benefits from allowing such bidding is questionable,” it said in an April filing with FERC that included a raft of other EIM-related Tariff changes. The ISO cited the low liquidity in the 15-minute market at the ISO’s own seams — suggesting a lack of market interest — and the potential for EIM participants to incur increased transaction costs from external bids.
EIM participants will continue to have the choice of allowing external intertie bidding along their seems in light of FERC’s ruling.
CAISO also envisioned a “problematic” scenario in which EIM transmission flows could shift as a result of only one EIM participant requesting economic bidding at its interties. While the market consists only of three BAAs today, Arizona Public Service and Puget Sound Energy are scheduled to begin participating later this year, while Portland General Electric will join next year.
The Western Power Trading Forum (WPTF) — an industry group representing power marketers — filed the only protest against the proposal, calling the revision an “attempt to codify” an “effective roadblock to market evolution” that discriminated against third-party participation in the EIM. The organization accused CAISO and the other EIM participants of resisting making the changes required “to incorporate external resources [into] the EIM with efficient, flexible market-based mechanisms.”
The group also criticized the open-ended nature of the Tariff change, asking the commission to dismiss the proposal until the ISO provided a plan to implement EIM intertie bidding by a specific date. The organization suggested that FERC direct the ISO to undertake an “open and transparent” stakeholder process to develop the necessary rules and commit to implementation within a year.
Although the WPTF didn’t win the one-year deadline it sought, the group’s arguments largely found support with the commission.
“As an initial matter, we find it inappropriate for CAISO to include in its Tariff an indefinite placeholder,” the commission wrote, referring to CAISO’s failure to propose a timeline for resolving the intertie issue.
While acknowledging that CAISO “identified issues that warrant further evaluation,” the commission ruled that the ISO had not “sufficiently described” those issues or met its burden under the Federal Power Act to alter the Tariff in a way that would remove from EIM participants the discretion for implementing intertie bidding.
“Moreover, WPTF raised concerns about unduly delaying the ability of external resources to participate — concerns that CAISO does not full address,” the commission said.
WPTF won another concession: The commission called for further discussion of the issue, directing FERC staff to convene a technical conference to gather information about the challenges of implementing economic bidding at the EIM’s interties — with an eye to determining how to overcome impediments. Details for the conference will be set out in a subsequent notice.
The commission’s June 30 ruling did approve CAISO’s other proposed EIM-related Tariff revisions, which included:
Modification of the ISO’s method for assigning congestion revenues to EIM participants to more accurately reflect those participants’ contributions to congestion at an intertie. The current rule allocates revenues based on the number of participants that share ownership of the intertie.
A provision allowing CAISO to submit outage information to the regional reliability coordinator on behalf of each EIM participant.
An alteration to the calculations underpinning the start-up/minimum load costs and default energy bids for EIM generators that would exclude CAISO’s grid management charge, which EIM-only generators do not pay. Instead, they pay EIM administrative charges, which they can continue to include in their costs.
A requirement that EIM participants accept approved, pending and adjusted e-Tags as the only valid means to convey an import/export base schedule to another participant for the purposes of imbalance settlement.
Great Plains Energy and Westar Energy filed a joint application with the Kansas Corporation Commission to approve the $12.2 billion sale of Westar to Great Plains.
The Eau Clair Energy Cooperative has hit upon an energy-saving, green method of controlling the vegetation at its solar farm in Fall Creek: sheep.
Alliant Energy has put Wisconsin’s largest solar installation, built on top of a coal-ash landfill, into service.
Pipeline giant Energy Transfer Equity has called off its proposed acquisition of Williams Co., following a Delaware judge’s ruling that the transaction could be terminated. The deal was valued around $38 billion, including debt, when it was reached in September.
GridLiance and the Kansas Power Pool announced a collaboration to improve the transmission infrastructure in KPP’s service area.
San Diego Gas and Electric is the first California investor-owned utility to meet its cap under the state’s original net energy metering (NEM) rule, which restricts projects eligible for net metering to 5% of a utility’s peak load.
The newly expanded Panama Canal locks will be able to handle 90% of the world’s LNG tankers, reducing shipping time and expense for shipments to Asia from Gulf Coast terminals, according to the Energy Information Administration.
The 6th U.S. Circuit Court of Appeals, rejecting a Sierra Club challenge, has ruled that an Enbridge oil pipeline that crosses a national forest in Michigan doesn’t need a new permit to keep operating.
