FERC issued seven orders Wednesday revising how MISO deals with its neighbors when incorporating power flows between the RTO and Manitoba Hydro.
The changes affect bidirectional external asynchronous resources (EARs). FERC defines an EAR as “a resource representing an asynchronous DC tie between the synchronous Eastern Interconnection grid and an asynchronous grid that is supported … through dynamic interchange schedules.” Only Manitoba Hydro’s generation currently meets the EAR definition in MISO.
Until 2015, the utility’s hydropower was a dispatchable import into the MISO footprint. In March 2015, however, the RTO and Manitoba began a bidirectional service that allowed the RTO to also export to its northern neighbor.
Slave Falls Generating Station | Manitoba Hydro
MISO said the revisions to the baseline congestion management process align the treatment of export EARs with the treatment of import EARs in the market flow calculations under its congestion management process.
FERC on Wednesday approved revisions, effective June 1, 2017, to:
MISO’s proposed changes followed an August 2015 memorandum of understanding among MISO, PJM and SPP that addressed EARS and other seams coordination issues. The RTO and Manitoba subsequently agreed to amend their Seams Operating Agreement, and MISO received guidance from NERC that resulted in additional proposed changes to the congestion management process.
The revised MISO-SPP JOA creates a process under which MISO will, on request, conduct studies to determine the flowgates impacted by an EAR.
MISO’s revised JOAs with SPP and PJM add an additional notification requirement when an RTO permanently adds or removes a point of interconnection.
The changes to the MISO-PJM JOA also detail other information sharing obligations and align day-ahead energy market coordination and the auction revenue rights/financial transmission rights with market-to-market settlement practices, MISO said.
FERC on Wednesday rejected MISO’s proposed cost allocation plan for interregional projects outside the RTO, saying it had not demonstrated the reasonableness of the methods detailed in the proposal (ER17-387).
Under MISO’s joint operating agreements with PJM and SPP, a transmission project can qualify as interregional even if it is in only one of the two neighboring RTOs, as long as it provides benefits to the other. MISO said that although no such projects are part of its Transmission Expansion Plan, interregional studies currently underway could result in such projects.
Proposal
In its filing last November, the RTO proposed that its portion of costs from an:
Interregional reliability transmission project terminating wholly within SPP or PJM — that is, with no interconnection to any MISO transmission facility — be allocated to those entities who would have paid for the MISO regional transmission projects that the interregional project avoids;
Interregional economic transmission project terminating wholly outside MISO be allocated 100% to the benefiting local resource zones based on adjusted production cost savings (interregional reliability projects terminating wholly within SPP that provide economic benefits to MISO would be allocated in the same manner); and
Interregional public policy transmission projects terminating wholly outside MISO be allocated to parties who would have paid for the MISO regional projects that the interregional project supplants.
The RTO intended to use the method only until the end of its five-year Entergy integration transition period, which ends in December 2018.
In approving Entergy joining MISO, the commission accepted a revised planning and cost allocation framework with two planning areas, one covering the pre-existing MISO members and a new second planning area (MISO South) including Entergy. The RTO said the transition was necessary because transmission planning for the existing MISO footprint and MISO South had not been done under a common process using the same criteria.
FERC rejected MISO’s proposed cost allocation plan for interregional projects outside the RTO, sending the issue back to a divided stakeholder body. | MISO
The transition cost allocation rules, which eliminated MISO’s footprint-wide postage-stamp method, are spelled out in Attachment FF-6 of the the RTO’s Tariff.
The RTO said that without the changes it proposed in November, interregional transmission projects wholly outside the MISO footprint would be allocated under Attachment FF. The costs of an interregional economic transmission project that terminates wholly outside of MISO would use the non-transition market efficiency project cost allocation: 80% to the benefiting zone, 20% postage stamp across the entire MISO footprint. The RTO said that would violate the intent of Attachment FF-6.
FERC Misgivings
FERC first indicated its misgivings with the proposal in a deficiency letter in January, which asked MISO to explain why it was just and reasonable to apply different cost allocation methods based solely on the location of the interregional project.
But the commission ruled that the RTO failed to demonstrate that its proposal would allocate costs in a way “that is at least roughly commensurate with the benefits received.”
“Notwithstanding the fact that the commission has determined that both [multi-value projects (MVPs) and market efficiency projects (MEPs)] provide regional benefits and are appropriately cost-allocated regionally, at least in part, MISO proposes to eliminate the regional cost allocation component for its share of market efficiency projects and multi-value projects that terminate wholly outside MISO,” the commission said. “However, MISO provides no evidence or analysis to demonstrate that the benefits of interregional transmission projects that terminate wholly outside MISO … accrue to a more narrow range of customers than the benefits of any other multi-value project or market efficiency project, including those that physically cross the seam between MISO and another transmission planning region.”
FERC rejected the RTO’s contention that it had previously approved similar cost allocation methods, saying that most of the proceedings cited by the RTO addressed interregional cost allocation methods. “Here, however, MISO is not proposing an interregional cost allocation method; it is proposing regional cost allocation methods that it will use to allocate within MISO the portion of the costs of interregional transmission projects.”
FERC said that although it has approved avoided-cost-only interregional cost allocation methods and an avoided-cost-only regional cost allocation method for reliability projects, “the commission has not previously addressed whether a transmission planning region may use an avoided-cost-only regional cost allocation method for public policy-related transmission projects.”
“This is consistent with the commission’s previous explanation that because Order No. 1000 has different requirements for regional transmission planning and interregional transmission coordination, a just and reasonable interregional cost allocation method may nevertheless be an unjust and unreasonable regional cost allocation method.”
Stakeholders Split
FERC’s rejection means that the issue will return to MISO, where it has divided stakeholders. FERC said the RTO told the commission that if its proposal was rejected, it would not apply the non-transition period cost allocation methods under Attachment FF to interregional projects outside the RTO, “and therefore will have to revisit this issue with its stakeholders.”
MISO told FERC that about half its stakeholders supported the revised Attachment FF-6 while the other half wanted to retain the non-transition period MEP cost allocation in Attachment FF for interregional economic projects entirely outside of the RTO.
Because it rejected MISO’s filing, the commission said it did not have to address protests by the New Orleans City Council, E.ON Climate & Renewables N.A. and EDF Renewable Energy.
The two renewable companies complained about MISO’s criteria requiring MEPs be rated at 345 kV or higher and meet a 1.25:1 benefit-cost ratio, saying they were impeding the development of MEPs. They asked the commission to reject the RTO’s proposal or condition its acceptance on removing the 345-kV threshold and lowering the benefit-cost ratio to 1:1.
New Orleans contended that a MISO analysis had shown that individual transmission owners in benefiting local resource zones may not always receive production cost savings from sub-345-kV economic transmission projects.
The commission also declined to respond to regulators from Arkansas, Louisiana and Mississippi, who sought clarification about which cost allocation methods would apply if the commission rejected the RTO’s proposal.
“MISO states that it will revisit the issue with stakeholders if its proposed cost allocation methods are rejected, and we will afford MISO the opportunity to do so,” the commission said.
FERC on Wednesday approved Exelon’s request for recovery of more than $1.5 million in fuel costs for its natural gas-fired Mystic Generation Station in Everett, Mass. (ER17-933).
The commission order granted Exelon $1,554,854 for Mystic Units 8 and 9 fuel costs that were not recovered because of market power mitigation measures applied last October and November.
ISO-NE’s Internal Market Monitor challenged Exelon’s request for cost recovery for mitigated hours on three days in October 2016, arguing that the company did not adequately provide data in its initial request, and that further supplemental information was submitted past the due date under the RTO’s Tariff.
Mystic Generation Station
“We disagree with the IMM’s position that Exelon’s alleged failure to timely submit information to the IMM for operating days Oct. 1, 3 and 4, 2016, precludes Exelon from seeking additional cost recovery for those days,” the commission said in response. “We do not find that failure to meet that deadline alone necessarily operates as a procedural bar to submitting a [Federal Power Act] Section 205 filing for additional cost recovery or renders such a filing unjust and unreasonable.” It noted that Exelon’s initial filing was submitted on time and that the Monitor did not dispute that certain required information was unavailable to the company at the time.
Exelon also asked to recover nearly $57,000 in regulatory costs in connection with its filing, as well as additional regulatory costs it might incur in connection with the proceeding after the date of its filing. The commission granted this request subject to a compliance filing due in 60 days that details the total regulatory costs.
CAISO’s Board of Governors on Tuesday unanimously approved rule changes that would allow market participants to partake in a program that models generator outages and the impact of remedial action schemes (RAS) on market operations.
During a presentation to the board, CAISO Director of Market and Infrastructure Policy Greg Cook said “stakeholders are generally supportive of the proposal” — but some still worry about unintended consequences.
The board’s vote greenlights modeling of generator contingencies and RAS in the day-ahead and real-time markets, as well as the congestion revenue rights allocation process, but the package still requires approval by FERC.
CAISO’s current modeling only addresses situations in which a transmission line goes down, potentially causing overflow on other lines. The new generator modeling reflects how the system will react to the loss of generation and is meant to ensure that transmission lines are not overwhelmed as the system picks up to address the unexpected shutdown of a generator.
RAS are protective processes that automatically disconnect generators or load to prevent transmission line overload in the event that another line goes out. The new method will update the ISO’s security constrained economic dispatch by modeling the loss of generation within the dispatch, as well as modeling the loss of transmission and generation because of RAS operations. The ISO currently uses manual, out-of-market dispatches to manage generator contingencies.
The changes will alter the congestion component of LMPs so that they consider the cost of positioning the system to account for generator contingencies and RAS operations. A RAS-connected generator does not increase congestion and will potentially receive higher energy prices than other generators at the same bus.
The Western Energy Imbalance Market (EIM) Governing Body on Sept. 6 approved the rule changes for generators that are within the EIM but outside the ISO. (See EIM Body Approves Generator Loss Modeling Plan.) Body Chairman Doug Howe on Tuesday urged the CAISO board to carefully implement the proposal.
Howe said the change will increase the efficiency of the real-time market across the EIM, improve dispatch and lead to more accurate market prices. But he also urged the ISO to ensure the new rule doesn’t create market abuse or too much complexity.
Southern California Edison raised concerns that the program would create a new value stream that could incentivize participants to pursue RAS rather than building new transmission. A company representative questioned whether generators on RAS should be rewarded with higher locational prices.
Trying to value RAS resources “gives us pause,” and the implementation should be carefully monitored, said SCE Director of State Legislative Policy Catherine Hackney. SCE has thousands of megawatts of generation under RAS.
“We need to be vigilant about watching and being wary and being able to respond if things don’t go exactly how we like,” Hackney said.
When it unveiled the proposal in May 2016, CAISO said it had more than 20 RAS modeled within its own system, with more throughout the Western Interconnection. (See Stakeholders Wary of CAISO Contingency Modeling.) The ISO currently factors RAS into its market operations through adjustments to its market software but views that approach as inadequate.
FERC on Wednesday rejected an argument by the California Public Utilities Commission that it erred last year in allowing Pacific Gas and Electric to include a 50-basis-point ISO participation adder in the utility’s 2017 transmission rates proposal.
The PUC filed its protest last November after FERC conditionally accepted PG&E’s proposed rate increase while at the same time denying the PUC’s request to throw out the adder, calling it a $30 million “unjustified windfall” at the expense of California ratepayers. (See CPUC Contest ISO Incentive for PG&E.) The Sacramento Municipal Utility District joined the protest.
The PUC at the time contended that the ruling ignored “the need to demonstrate that an incentive must be ‘justified’ pursuant to [FERC] Order 679,” which allows transmission owners to collect the adder as motivation to join an RTO or ISO. Because the PUC requires California’s investor-owned utilities to be members of CAISO, PG&E did not warrant incentive treatment, the PUC said.
The commission’s Sept. 20 order rebuffed that argument, saying that the PUC had raised the same argument more than 10 years ago in its rehearing request of Order 679, which was rejected in a follow-up order (ER16-2320).
Pacific Gas and Electric transmission lines | PGE
“If the CPUC disagreed with the commission’s determination in Order No. 679-A, the appropriate course of action was to seek judicial review of Order Nos. 679 and 679-A under Section 313 of the” Federal Power Act, FERC said. “The commission has also already held that arguments opposing the granting of an incentive adder for RTO membership to existing RTO members constitute a collateral attack on Order No. 679-A, and we find that the CPUC’s assertion here is in the same vein and warrants the same response.”
The commission also rejected the PUC’s contention that FERC erred by granting the 50-basis-point adder without weighing the specific facts of the case and considering whether a different incentive might be more appropriate. The PUC noted that FERC’s September 2016 order had subjected PG&E’s final return on equity to a hearing by a settlement judge. (See FERC Sets PG&E Rate Increase Proposal for Talks.)
FERC said it approved the adder subject to it being it being applied to a base ROE that left the full ROE within the “zone of reasonableness” determined by the settlement judge.
“Thus, the commission’s duty to ensure just and reasonable rates for consumers will be fulfilled via the trial-type evidentiary hearing process we have ordered, which will result in an ROE, including the proposed adder, that must fall within the zone of reasonableness, and that trial-type evidentiary hearing process is one in which the CPUC may participate,” FERC said.
FERC also said it was “not persuaded” by the PUC’s contention that PG&E’s continued membership in CAISO is not voluntary. It noted that FERC Order 2000 spelled out that voluntary membership was the “most appropriate” approach for creating and expanding RTOs and ISOs.
“This longstanding commission policy of voluntary RTO/ISO formation and membership remains unchanged,” FERC said. “This longstanding commission policy is also reflected in CAISO’s currently effective Transmission Control Agreement, which is on file with the commission.”
SARATOGA SPRINGS, N.Y. — Refurbishing an existing combined-cycle plant can squeeze an extra 12 to 15 MW of generating capacity from each gas turbine — and the compelling economics of equipment upgrades provide New York generators a choice beyond building new plants.
That was the view of Bob Prantil, executive director of sales and strategic accounts for GE Power North America, who spoke Sept. 14 at the fall conference of the Independent Power Producers of New York.
“After all the debates and discussions, eventually electrons need to be placed on a grid at the lowest LCOE [levelized cost of electricity] to make sure that whoever is providing those electrons can break even,” Prantil said. “We recently combined our power business with our grid business because that’s what the market wanted. When you’re going to speak to a utility, it’s not just necessarily about generation. You have to figure out how to get those electrons around.”
Existing Versus New Generation
While New York has a goal of getting 50% of its electricity from renewable resources by 2030, Prantil pointed out that other states are looking at more. Iowa, for example, aims to reach 100% renewable energy over the next five years.
“You all know the complexity of new generation from the standpoint of permitting and do people want it in their backyards — and the construction, where it makes sense,” Prantil said. “I would just challenge you to understand the existing generation that you have in-state already and what [original equipment manufacturers] can do to reduce overall CO2 emissions, gain more efficiency and get more output from those plants at a quarter of the price of a new plant being built.”
Energy conferences these days focus more on renewables and efficiency than on gas, which strikes Prantil as odd.
“Especially in the northeast United States, if you see what’s going on in PJM, there has been an uptick in the installation of combined cycle plants,” he said. “If you think about the sizes of gas turbines now and the efficiencies of those turbines compared to just 10 years ago, it makes the decision to go with gas, as some people call it, a bridge fuel before 100% renewables, a very smart decision.”
GE Power’s 9HA.01 gas turbine helped the company earn a Guinness World Records™ title for powering the world’s most efficient combined-cycle power plant in Bouchain, France. | GE Power
GE Power just set a world record with the company’s first plant in France. Prantil said the combined cycle unit is 99.95% available and achieved a record-setting 62.6% thermal efficiency, 5 percentage points higher than the best combined cycle plants could have achieved just five years ago.
“If you take that efficiency over the life cycle of a plant and then you look at the LCOE for that, and you think about the saved BTUs and CO2, it’s a pretty compelling story,” Prantil said.
Energy Storage and Hybrids
GE built one of the first battery plants in the U.S. in Schenectady, N.Y. “So we know how to do all this,” Prantil said. “We believe that energy storage prices are going to come down.”
He said California has been doing generation-storage hybrids longer than New York, but instead of trying to figure out how to create new markets — which is what New York is doing — GE is looking at how to take an existing market and apply battery technology to it. He cited a case in California where GE applied storage technology to the famed “duck curve.”
“That power needs to be instantaneous, almost like spinning reserve,” Prantil said. “So if you take a 50-MW gas turbine that takes eight or nine minutes to ramp up to speed … you put in a four-hour battery that’s being charged by the grid. We can have the battery take over for the seven minutes of ramping.”
GE sees energy storage as a very cost-effective way to meet some of the ancillary requirements of RTOs and ISOs — and there has to be an ancillary service for any developer to do it and get paid.
GE workers with GE 9HA.01 gas turbine at factory in Belfort, France | GE Power
“We always want to get the EEI [Edison Electric Institute] award for a 1,200-MW combined cycle plant or some offshore wind farm, but we got the EEI award for a 15-MW battery hybrid system,” Prantil said.
Energy efficiency is also driving changes to the dispatch stack, which will also occur in NYISO, he said.
“A developer will look at what zone they’re in, and if there’s a combined cycle plant in that zone, they want to know the efficiency of that plant. And if a generator can build a more efficient plant in that zone, or increase the efficiency of an existing plant, their capacity is more likely to get dispatched.”
New York Native
A native New Yorker schooled in Brooklyn, Queens and the Bronx, Prantil said GE is also a native of the state.
“The headquarters of our GE Power business from the very beginning, from the Thomas Edison years, is located 20 miles from here in Schenectady,” he said.
Prantil noted that GE technology has outfitted about half the state’s nuclear fleet and wind farms, as well as providing 152 gas turbine units and 116 steam and hydro turbine units.
“We like to say that New York is powered by GE, as 60% of the megawatts generated in New York comes from GE equipment,” Prantil said. “We have 152 gas turbine units, we have 116 turbine units, half of the nuclear fleet is with GE technology and about 50% of the installed blades in wind is with GE technology.”
If New York decides to go heavily into offshore wind, GE’s not going to debate if that’s right or wrong, he said, but will instead figure out how to develop the resources at the lowest cost.
Environmental advocates criticized FERC for ruling last week that New York state failed to act in a timely manner on water quality permits sought by Millennium Pipeline.
New York State Department of Environmental Conservation Headquarters
In its Sept. 15 order, the commission ruled that the New York State Department of Environmental Conservation (DEC) had waived its authority to issue or deny a water quality certification for the project by failing to act within the one-year time frame required by the Clean Water Act (CP16-17).
In a statement, the department said it is reviewing FERC’s decision and would “consider all legal options to protect public health and the environment.” It would have to file any appeal with the D.C. Circuit Court of Appeals.
But opponents of the natural gas pipeline extension — the 7.8-mile Valley Lateral spur to the Valley Energy Center in Wawayanda, N.Y. — were not as circumspect.
“This is just another warping of the law by FERC,” Maya van Rossum, director of the Delaware Riverkeeper Network, told RTO Insider. “It’s not the first time, and it probably won’t be the last, that FERC acts only to help its friends in the pipeline industry.”
Sierra Club Atlantic Chapter Director Roger Downs said in a statement that “nowhere is FERC granted the right to override” a state’s authority to regulate its water quality.
Timeliness of the Essence
Millennium Pipeline in July filed with the commission a request for notice to proceed with construction, asserting that the DEC had failed to act before the statutorily imposed deadline. The department responded days later that it had not waived its authority, which it exercised on Aug. 30 when it denied Millennium’s application for certification.
| Millenium Pipeline
Millennium and the department differed on when the one-year review process began, with the company contending that the clock started ticking when it submitted its application to DEC in November 2015. The DEC countered that the one-year period did not begin until it received a “complete” application on Aug. 31, 2016. (See Pipeline Sues to Force NY to Issue Permit for CPV Plant.)
FERC said in its order that the “starting point for interpreting a statute is the language of the statute itself,” and that “Section 401 [of the Clean Water Act] provides that water quality certification is waived when the certifying agency ‘fails or refuses to act on a request for certification, within a reasonable period of time (which shall not exceed one year) after receipt of such request.’ Thus the term ‘receipt’ specifies the triggering event.”
The commission ruled that “giving effect to the plain text of a statute, the one-year review period began November 23, 2015” — when the DEC received the application.
New Pattern
Gavin Donahue, CEO of the Independent Power Producers of New York, last week told participants at the group’s fall conference that “the siting of natural gas pipelines is FERC’s jurisdiction, but the DEC has developed a pattern of denying water quality certificates for projects, most recently evidenced by the decision on the Millennium Pipeline.” (See NYPSC Chair Promises ‘Continuity’ on State Energy Policies.)
New York environmentalists might have thought they were succeeding in stopping pipelines after the 2nd U.S. Circuit Court of Appeals last month ruled that the department acted within its authority to deny water quality permits sought by Williams Co. for its Constitution Pipeline.
Now the natural gas industry sees hope. Following the Millennium order, Reuters reported that Williams now plans to seek a similar permit ruling from FERC.
The Trump administration sided with utility witnesses Tuesday on legislation to streamline approvals for managing vegetation near power lines on federal land, an effort to reduce wildfire risks.
Witnesses from the Bureau of Land Management, the National Forest Service and two utilities endorsed separate House and Senate bills to amend the Federal Land Policy and Management Act (FLPMA) and provide authority to exempt existing rights of way (ROWs) from reviews under the National Environmental Policy Act (NEPA).
The Wilderness Society, however, said it opposed the House bill, the Electricity Reliability and Forest Protection Act (H.R. 1873), because it would impose “counterproductive limitations and obligations on both utilities and federal land managers, inappropriately shift costs from utilities to taxpayers and agencies, and undermine the public interest in the management of their public lands.”
Witnesses from the Bureau of Land Management, the National Forest Service and two utilities endorsed separate House and Senate bills to streamline approvals for managing vegetation near power lines on federal land. Left to right, Glenn Casamassa, National Forest System; John Ruhs, Bureau of Land Management; Mark Hayden, Missoula Electric Cooperative; Scott Miller, The Wilderness Society, and Andrew Rable, Arizona Public Service. Miller said he supports a Senate bill but not the House legislation.
The group told a Senate Energy and Natural Resources Committee hearing Tuesday that it prefers Section 2310 of the Energy and Natural Resources Act of 2017 (S. 1460), a comprehensive energy bill cosponsored by committee Chair Lisa Murkowski (R-Alaska) and ranking member Maria Cantwell (D-Wash.).
Blackout Prompted Standards
It was the August 2003 Northeast blackout — triggered by contact between a power line and a tree — that led Congress to enact mandatory reliability standards as part of the 2005 Energy Policy Act. FERC, which deputized NERC to develop the standards, approved the corporation’s vegetation standards in 2013.
Both bills pending before Congress would provide authority to exempt existing ROWs from reviews under NEPA. They also would allow utilities to trim vegetation within ROWs or “hazard” trees adjacent to ROWs that have contacted or are in imminent danger of contacting transmission lines as long as they notify the appropriate agency within 24 hours, according to summary attached to BLM’s testimony.
Rable
Testifying for the Edison Electric Institute, Andrew Rable, manager of forestry and special programs for Arizona Public Service, laid out utilities’ difficulties in employing integrated vegetation management (IVM), which combines the planting of low-growth vegetation in ROWs with pruning and use of herbicides to ensure sufficient distance between plants and electric facilities.
“Transmission line ROWs crossing federal lands face multiple layers of jurisdiction and decision-making, which can hamper electric companies’ ability to manage vegetation and reduce wildfire risk in a timely manner,” he said.
Rable said that although the two bills are largely similar, the House’s is preferable because it sets shorter deadline for approval of vegetation management plans (90 days versus 180 days) and provides “more flexible and less burdensome” rules.
The two bills both provide limited liability protections. According to the BLM summary, the House version protects a utility from wildfire liability to the U.S. when federal agencies blocks it from addressing hazard trees or vegetation in imminent danger of contact with power facilities. The Senate’s would protect utilities from strict liability following a land agency’s “unreasonable delay or failure to approve or adhere to a vegetation management plan or an MOU,” BLM said.
Hayden
Mark Hayden, general manager of the Missoula Electric Cooperative, which has about 15,000 customers in western Montana and eastern Idaho and 300 miles of distribution lines crossing federal land, told the committee the 2017 wildfire season has devastated his region’s economy.
“I fully recognize that the fires burning in Montana today were all lightning sparked. But for me, these fires serve as a vivid reminder and warning of what could occur as a result of long delays in permit approvals and inconsistent application of policies by federal land managers,” said Hayden, who said the ability of utilities to develop relationships with federal officials is hampered by frequent turnover at Forest Service district offices.
Examples Cited
Hayden cited a New Mexico cooperative that received a $38.2 million bill from the Forest Service — almost twice the co-op’s $20 million in liability insurance — for the costs of fighting a 152,000-acre fire caused when a tree fell onto a power line.
The Benton Rural Electric Association in Prosser, Wash., applied to renew its ROW permit in August 2015, four months before it was due to expire. “After waiting 15 months, Forest Service officials have now proposed nothing short of a full blown environmental assessment for which costs could exceed $100,000 for facilities that have been in place for more than 70 years,” Hayden said.
In 2009, when the Missoula co-op felled trees killed and weakened by an insect infestation, the Forest Service required it to remove the timber “using an expensive, labor-intensive method to minimize impact to ‘flora and fauna’ from mechanical equipment,” Hayden said. “Ironically, the Forest Service conducted a timber sale on the same tract later in the year using the exact mechanical forestry techniques that we were prohibited from employing. In essence, we were held to a higher standard than they held themselves.”
When the co-op requested permission to bury about 6 miles of overhead lines on Forest Service land, approval took 18 months — granted just days before Hayden was to testify before Congress regarding the delay.
BLM Committed to Streamlining Process
Ruhs
John Ruhs, acting deputy director of operations for BLM, said his agency supports both bills and “is committed to improving and streamlining its permitting processes.”
The agency, which administers almost 16,000 authorizations for electricity transmission and distribution facilities, allows utilities to conduct “minor trimming, pruning and weed management” after notifying the agency, Ruhs explained. Trees that present an imminent hazard can be removed without BLM pre-approval. “For actions that fall outside the scope of the ROW grant and do not present an imminent threat, BLM approval is needed, and additional analysis may be required.”
Ruhs said the legislation “would expand the BLM’s toolbox to help reduce the threat of catastrophic wildfires like those we are currently experiencing.”
Casamassa
Glenn Casamassa, associate deputy chief of the Department of Agriculture’s National Forest System, said his agency supports most of the language of both bills. But Casamassa said some provisions duplicate existing requirements in Forest Service policies.
“USDA is aware of the frustrations some utilities experience as a result of delayed responses for maintenance approvals and inconsistency across agency field offices and has been actively taking steps to address these concerns under existing authorities,” he said. The Forest Service has 2,700 authorizations for 18,000 linear miles of power lines.
Climate Change Impact
Miller
Scott Miller, senior director for The Wilderness Society’s Southwest region, said utility vegetation management (UVM) practices have improved substantially since 2005. “At the same time, the importance of strong UVM practices continues to grow as climate change is causing longer wildfire seasons, larger and more severe wildfires, longer growing seasons, changing plant species distributions, increased insect and disease activity, and more intense, more frequent and longer-lasting drought, wetness and weather events,” he said.
Miller said the society, which claims more than 1 million members, opposes H.R. 1873 because it “fails to appropriately recognize the federal land management agencies’ obligations or the public’s interest in federal land management and because it fails to provide for the necessary cooperation that will improve effective and sustainable UVM on federal lands.”
The Senate bill, in contrast, provides “a thoughtful framework for legislation to advance UVM on public lands” and “corrects the many flaws” of the House bill.
“H.R. 1873 would prevent utilities and land managers from including activities in vegetation management plans that would require anything beyond annual notice, description and certification by the utility for its planned activities. It also would give utilities (including those without approved plans) blanket approval to conduct vegetation management activities to meet clearance requirements, leaving the agencies with no authority but to allow such activities, and leaving the utilities with little incentive to cooperate or even prepare a vegetation management plan.”
Granting a blanket exemption for vegetation management from NEPA “would undermine sound stewardship of our public lands,” he continued. “We note that both the Forest Service and BLM have already established a number of categorical exclusions that apply to many routine UVM activities, and those authorities are routinely utilized by the agencies in the context of UVM.”
The Senate bill, in contrast, would encourage cooperation between utilities and federal land managers, he said.
The group said the House bill’s provisions on liability are “overbroad and unclear.”
“Nothing in the bill states that the release of liability is limited to situations where the secretaries’ decisions are an actual and proximate cause of the damages, potentially leaving the agencies (and ultimately, taxpayers) to cover the damages caused by the utilities’ negligence (or even gross negligence).”
CARMEL, Ind. — MISO will file a response to FERC’s recent deficiency letter on the RTO’s new constrained area category after an internal review, stakeholders learned on Thursday.
FERC issued the letter Sept. 6 (ER17-2097), inquiring about:
What past outage information or expected future congestion estimates MISO plans to use to impose a dynamic narrowly constrained area designation;
What conduct and impact thresholds MISO plans to use for mitigation;
Whether dynamic narrowly constrained areas could also be simultaneously designated as simple narrowly constrained areas;
Whether MISO’s existing binding reserve zone constraints would be used to apply mitigation measures
MISO Director of Market Evaluation and Design Dhiman Chatterjee said the RTO is working with its Independent Market Monitor to respond to the deficiency letter.
“We believe those are more clarifications [than changes] that they’re asking for. It’s a matter of providing more information, is our initial take on it,” Chatterjee said during a Sept. 14 Market Subcommittee meeting.
Under MISO’s proposal, filed July 14, dynamic narrowly constrained areas would address intense, short-lived congestion by allowing the Monitor to apply mitigation if the constraint has bound in 15% or more hours over at least five consecutive days. The definition would differ from FERC-defined narrowly constrained areas, which must bind for more than 500 hours annually. (See MISO Embraces Monitor’s New Constrained Area Category.)
The new category also would require the Monitor to have identified economic or physical withholding, or uneconomic production in the area. MISO proposed a $25/MWh “conduct threshold” for such determinations, meaning the behavior must have impacted LMPs or market clearing prices by at least that amount.
VALLEY FORGE, Pa. — Stakeholders at last week’s Market Implementation Committee meeting endorsed the first phase of what amounts to a two-phase implementation of Manual 11 revisions to facilitate intra-day generation offers.
PJM was requesting endorsement of manual revisions needed to implement intra-day offers on Nov. 1 as planned. The proposal received 72% approval but not before a lengthy discussion about how frequently generators can elect to opt in or out of making changes to offers in real-time auctions.
PJM and its Independent Market Monitor have differed on the issue, but the two sides came to an agreement that market participants must specify in their annually approved fuel-cost policies (FCPs) the conditions under which they will opt in. This came as a surprise to several generation representatives, including Gary Greiner of Public Service Electric and Gas. He believed the language previously had read that generators would be able to make that election monthly.
PJM’s Lisa Morelli had called the change “minor,” but Greiner took issue with that characterization.
“What I’m hearing now is we have to build it into the fuel-cost policy so we no longer have that monthly option; that’s gone. It’s a once-a-year, permanent thing, unless we want to create a new fuel-cost policy that says we’d want to opt in and [include] everything around all of the mechanics of what we’re going to do intra-day. [Then] we have to stay with an opt-out decision for one year. Is that a minor change?” he asked. “That’s a massive change.”
“So, I should not have used the word ‘minor,’” Morelli acknowledged but pointed out that the language had been the same at the August Markets and Reliability Committee meeting. (See “Division Remains on Oversight of Intraday Offers,” PJM Markets and Reliability Committee Briefs: Aug. 24, 2017.)
PJM’s Jeff Schmitt said such flexibility could be worked into a generator’s FCP.
“As long as we have an approved fuel cost policy … we’d work with you to get there,” he said. “It’s certainly workable from my perspective.”
“I’m uncomfortable with having a predefined trigger that determines when I’m opting in or opting out,” Greiner said.
NRG’s Neal Fitch asked several questions to clarify whether he was correct in assuming that the new rules provided leeway for opting in and out more frequently than just annually.
“To the extent that there is a change in desire down the road, you’re not limited to once per year,” Fitch said.
PJM and the IMM remain at odds about whether market participants must specify in their FCPs the frequency with which they can update price-based offers.
“PJM isn’t necessarily opposed to having that level of detail, but we don’t think that it’s required,” Morelli said.
She also laid out the second phase of revisions, which will be presented for endorsement next month. They would change how offers are capped and how often the three-pivotal supplier (TPS) test is run.
PJM and the IMM mutually proposed re-evaluating which schedule, either the cost- or price-based, is cheapest and reapplying the offer cap when offers are updated. The current rules do not allow for such re-evaluation, which wouldn’t allow market power mitigation to keep up with intraday updates. Since units can self-schedule with 20 minutes of notice, PJM and the IMM proposed running the TPS test on such units every hour following the first hour of operation.
Stakeholders also endorsed related revisions to Manual 28 by acclamation with no objections or abstentions.
MTSL Revisions Kaput
Stakeholders rejected a joint PJM-IMM proposal to revise how black start units are compensated for fuel storage, with some generators complaining that the issue is not significant relative to other issues the membership is addressing.
The measure, which would have paid units based on the portion of fuel they need for black start rather than how much is stored, received 48% approval. The proposal, which was based on the minimum tank-suction level (MTSL) for the fuel-storage tanks, would have saved customers about $210,000 annually. (See “PJM Indifferent on Black Start Fuel Compensation,” PJM MIC Briefs: July 12, 2017.)
NRG’s Fitch said the way the proposal was presented seemed “inappropriate” and “flawed.”
“I hope we do a better job in the future deciding when and where we need to work on the small stuff,” he said.
John Horstmann of Dayton Power and Light called the proposal “shortsighted” because the value of having fuel when needed during a system emergency far exceeds the “minuscule” savings from proportional compensation.
“You can’t even measure these savings on a customer’s bill,” he said.
Others, however, said the principle was the point.
“The status quo is not defensible. There are units being paid more than it takes to provide black start service,” the IMM’s Catherine Tyler said.
“I realize that these are not major dollars, but dollars are dollars, and customers have to pay those dollars,” said John Farber with the Delaware Public Service Commission.
The Monitor noted that the final proposal was a compromise between it and PJM. The RTO estimated the pro rata calculation would have reduced payments by about 95%, so it included a $12,000 “dual-fuel unit adder” that only cut payments in half.
“We do feel that the dual-fuel adder is somewhat arbitrary,” Tyler said, adding that it would need to be justified or eliminated in the future.
FTR Forfeiture Rebilling to Start
PJM’s Brian Chmielewski announced that, barring any further action from FERC, implementation of PJM’s revised financial transmission right (FTR) forfeiture rule will begin with September billing statements and rebill back to the Jan. 19 effective date of the related FERC order. Manual revisions to address the changes ordered by FERC received 82% approval in an endorsement vote.
FERC’s order on the issue (EL14-37) required PJM to evaluate the net effect of a market participant’s entire virtual portfolio of up-to-congestion trades (UTCs), incremental bids (INCs) and decremental offers (DECs) on congestion constraints. A forfeiture is triggered if at least 75% of the energy flowing between the bus where a virtual transaction is made and the worst-case bus — the location at which the transaction has the biggest impact on congestion — is reflected in the constraint. (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)
Following PJM’s request in 2013 to define UTCs as virtual transactions, FERC initiated an investigation to examine how PJM planned to apply its FTR forfeiture rule to UTCs. PJM had implemented the rule in 2000 to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions but hadn’t included UTCs.
“We just rewrote the entire section because it’s essentially an entirely different, new rule,” Chmielewski said of the manual revisions. “We are on the same page with the IMM. Our numbers are very close to matching.”
He acknowledged that the calculations under the revised forfeiture logic were higher, but “I wouldn’t say they are significantly more in all cases.”
“I think relative to total target credits, the percentage is still very low, but relative to the previous rule, they’re higher,” Chmielewski said.
Several stakeholders noted the existence of protests in the FERC docket, but Chmielewski said that wouldn’t impact the effective date.
Now is the Winter of Our Discontent (with DR Rules)
East Kentucky Power Cooperative’s (EKPC’s) Chuck Dugan proposed a problem statement and issue charge to investigate the impact of winter demand response (DR) not performing on an assessment day due to a maintenance outage. Such nonperformance on a winter peak day reduces a market participant’s winter peak load (WPL), which reduces the participant’s winter DR capacity nomination. An unexpectedly low nomination can result in needing to secure replacement capacity to fulfill a commitment and avoid a daily deficiency penalty, which happened to an EKPC customer, Dugan said.
“We’re paying the resources to be available all year,” said Tyler, adding that the Monitor opposes the proposal.
“They’re already doing what you paid them to do, which is be off,” Dugan countered.
Stakeholders will vote on the proposal at next month’s meeting.
EE Waiver for Kentucky?
Chris O’Hara, PJM’s deputy general counsel, said the RTO plans to submit a Section 205 filing with FERC asking for a prospective waiver of its Tariff to bar Kentucky participants from its energy efficiency resources (EERs) market. The waiver would be limited to Kentucky and only after FERC makes a ruling on the issue.
The request evolved from a Kentucky Public Service Commission staff finding in February that EERs are a retail product under its regulatory oversight that, like other Kentucky retail customers, aren’t eligible to participate in wholesale markets such as PJM. PSC commissioners issued a declaratory order to that effect on June 6. Four days earlier, Advanced Energy Economy requested that FERC declare whether it has sole jurisdiction over EERs.
“To the extent that’s a change to what we’ve said, it is a change,” O’Hara said in response to questions about whether PJM had revised its position on the issue. PJM received stakeholder endorsement to examine how it allows EER aggregations to participate in its wholesale markets. The initiative also was to investigate the potential for creating an “opt-out” mechanism for regulators like what PJM developed for demand response in response to Order 719. (See States, Enviros Differ on Jurisdiction over Energy Efficiency.)
EKPC’s Dugan supported the waiver request, sympathizing with PJM’s position “between a rock and [a] hard place” jurisdictionally. Tom Rutigliano, a consultant who represents EER clients, sought — and received — assurances that the waiver would not extend past Kentucky.
Tyler voiced concerns that PJM is requesting permission to discriminate among market participants “especially in a way that limits competition.”
