The New England Power Generators Association says ISO-NE should adhere to a planned change to a sloped demand curve in the next Forward Capacity Auction (ER14-1639).
NEPGA has asked the Federal Energy Regulatory Commission to clarify a previous order that directed the RTO to continue the effort to eliminate the need for administrative pricing in zones that are short of generation resources or suffer from transmission constraints.
ISO-NE informed FERC in May that the complexities involved in switching to the sloped demand curve could not be resolved in time to “result in just and reasonable outcomes” in FCA 10, which is scheduled for Feb. 8, 2016. ISO-NE also cited the need to reconfigure the zones within the RTO to resolve transmission constraints identified since the last auction as an impediment to a timely resolution. (See ISO-NE Proposes New Capacity Zones for FCA 10.)
NEPGA suggests that FERC did not explicitly order a sloped zonal demand curve “only because it relied on ISO-NE’s commitment to file sloped zonal demand curves for commission review in advance of FCA 10.”
NEPGA is asking the commission to initiate a Section 206 proceeding and order ISO-NE to file the sloped zonal demand curves developed by the RTO and New England Power Pool stakeholders.
“Market participants have expected for over a year that their participation in FCA 10 would be based on both system-wide and zonal sloped demand curves. Clearing capacity resources on a curve better reflects the incremental value of capacity and leads to a more efficient market outcome,” NEPGA wrote.
Opponents of Clean Line Energy’s proposed Plains & Eastern transmission line are asking for public hearings and a way to intervene on the project, which would span 720 miles from Oklahoma to Tennessee.
A group called BLOCK Plains & Eastern Clean Line: Arkansas and Oklahoma filed petitions with the Federal Energy Regulatory Commission and the Energy Department’s Office of Electricity Delivery and Energy Reliability on June 16, asking them to conduct a rulemaking for implementing Section 1222 of the Energy Policy Act of 2005.
The Plains & Eastern is the first transmission project being developed with the department under Section 1222, which authorizes the Southwestern and Western Area Power Administrations to participate in transmission projects with third parties in states where they operate if the department determines that they are necessary to reduce congestion or meet demand.
Section 1222 does not allow financial participation by those agencies, but it does authorize the Energy Department to facilitate private sector participation in transmission development by accepting and using third-party funds.
“There is no ‘normal process’ [for Section 1222],” Carol Overland, attorney for BLOCK Plains, said in an interview. “It’s not something ever used before and DOE has not established rules for Section 1222, so we have asked for a rulemaking.”
FERC rejected BLOCK Plains’ petition last week, saying Section 1222 “does not give the commission rulemaking or other authority regarding these matters and is therefore outside of the commission’s jurisdiction” (RM15-22).
Overland said BLOCK Plains has yet to hear from the Energy Department. However, the department has extended the public comment period to July 13, saying it is “accepting comments on whether the proposed project meets the statutory criteria listed in Section 1222 … as well as all factors included in DOE’s 2010 request for proposals.”
The department selected the Plains & Eastern project in 2012 under the RFP. Clean Line hopes to partner with the Southwestern Power Administration, which owns transmission lines and facilities in Texas, Oklahoma, Missouri, Louisiana and Arkansas. (See Clean Line Starts Online Petition for DOE Tx Approval.)
BLOCK Plains, which says its represents Arkansas and Oklahoma landowners, contends the department has improperly conducted reviews on the environmental impact of the project, its need and routing options without first creating a rulemaking process for Section 1222.
Due Process
“The process chosen by the department raises due process issues because there are no established rules, the department’s process severely limits public participation and transparency [and] restricts access to information, and thus far the department offers no opportunity for public hearings or intervention in a contested case,” the group said in its petitions. “The process chosen by the department also severely limits building a record that would support any decision by the department. There is no justification for operating without rules.”
The Plains & Eastern project would deliver more than 3,500 MW of energy from wind farms in the Oklahoma Panhandle to the southeastern U.S. The DC line would connect with the Tennessee Valley Authority.
The department has closed comments on a draft environmental impact statement for the project and is now preparing a final EIS. Clean Line hopes to begin construction on the Plains & Eastern project in 2016, with commercial operation as early as 2018.
New York’s Green Bank has generated so much interest from clean energy and energy efficiency developers that it is asking to borrow from the private markets as well as revise allocations from its state sponsor.
In a report filed with the New York Public Service Commission on Thursday, the bank’s sponsor, the New York State Energy Research and Development Authority (NYSERDA), said its schedule to capitalize the bank with $1 billion over five years is inadequate for its potential project portfolio.
It is asking the PSC for permission “to obtain an external borrowing facility to provide the necessary liquidity and the certainty of sufficient available capital that is critical for private sector engagement” (14-M-0094). The bank was initially funded with $200 million last year and has received requests for $734 million through mid-June.
In its annual business plan filed on June 19, the bank said it has received funding applications that could be leveraged into more than $3 billion worth of clean energy projects statewide.
‘Pillar’ of REV
The bank is one of four initiatives of New York’s Clean Energy Fund, which NYSERDA calls a “key pillar” of the state’s Reforming the Energy Vision program. The fund also includes the $1 billion NY-Sun initiative to build solar projects throughout New York. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
The bank’s business model is predicated on projects receiving $3 from the financial markets for every $1 in publicly backed funds.
More than half of the current funding requests — in both the number of projects and their financing needs — has come from energy efficiency programs. The rest is divided among wind, solar, bioenergy and other projects.
The $734 million in funding requests are in various stages of the bank’s pipeline. As of June 12, the Green Bank had $338 million of projects in its “active portfolio,” meaning they had passed advanced stages of review by its scoring committee. About $500,000 in transactions have closed.
The bank started in 2014 with plans to be capitalized with $1 billion in public funding over five years. Last year it received $165 million in ratepayer funds through the system benefits charge (SBC) and another $45 million from New York’s share of money from the cap-and-trade program of the Regional Greenhouse Gas Initiative.
Seeking Advance
NYSERDA says it appears the bank’s current funding levels will be unable to keep up with the amount of projects seeking aid.
The bank is seeking an advance of $150 million now to keep momentum going in the project pipeline. It would then draw funds from NYSERDA over a total of 10 years instead of five, with lower annual allocations over the extended time frame. It said the private credit facility it is seeking “would be put in place at the point it is needed, sized to ensure that the available amount would not itself become the constraint on [the bank’s] ability to run and grow its business.”
Without the $150 million, NYSERDA said, the bank will lose $1.5 billion in private investment over the next decade.
The bank’s aim is to become self-sustaining within a few years as loans are repaid and that money is recycled to fund future projects. The bank anticipates it will reach a “steady state” of annual commitments of about $200 million.
The bank was formed to leverage investment in clean energy technologies and energy efficiency programs that may not attract private capital on their own.
But the bank’s report says its expertise was also crucial in assisting two upstate clean energy projects that ultimately were financed through private sources. It cited a 60-MW biomass energy project at the U.S. Army’s Fort Drum, for which the bank was originally committed to purchase $10 million of its debt.
It also said its consultations with private banks helped familiarize them with an ongoing project to install solar arrays at several Finger Lakes region vineyards.
A merchant transmission developer last week accused several PJM transmission owners of inflating the costs of upgrades necessary to approve three auction revenue rights requests.
TransSource LLC asked the Federal Energy Regulatory Commission to order PJM to provide it with data showing how the RTO calculated the almost $1.7 billion in upgrade costs in its system impact studies (SIS) for the requests. TransSource said the RTO has repeatedly refused to release the data, in violation of its Tariff (EL15-79).
The company also requested fast-track processing of its complaint and asked that FERC suspend a July 12 deadline to execute facilities study agreements in order for the requests to retain their positions in the ARR queue.
TransSource — not to be confused with Transource Energy, a joint venture of American Electric Power and Great Plains Energy — said that if it misses the deadline and forfeits its queue positions, it could lose $6 million per month in incremental ARR revenues.
PJM estimated the requests, identified by their queue position numbers Z2-053, Z2-069 and Z2-072, to be worth, respectively, 156.1 MW, 105 MW and 204.6 MW in incremental ARRs. It estimated $376.5 million, $783.8 million and $586.8 million in upgrade costs.
TransSource alleges that the transmission owners whose lines would require upgrades necessary to award the ARRs “intentionally assigned to those queue positions a scope of mitigation that is materially too broad in an effort to defeat TransSource’s network upgrade request.”
Z2-053 and Z2-069 are both sourced in Bridgewater, N.J., and sink in Hoboken and South River, respectively. Z2-072’s source is the Indian River power plant in Delaware, and its sink is New Church, Va., on the Delmarva Peninsula. The ARRs require upgrades on lines owned by Public Service Electric and Gas, PPL, Jersey Central Power & Light and Delmarva Power & Light.
“On 12 occasions TransSource has asked PJM to explain how it determined the scope of mitigation used in its SIS and has requested access to the underlying data inputs, assumptions that the PJM TOs submitted to PJM and that PJM used to determine the SIS scope of mitigation and costs. Each time, PJM has refused,” TransSource said. PJM told TransSource that it had no right the data, according to the company.
TransSource pointed to the section in the PJM Tariff that requires the RTO to “provide a copy of the system impact study and, to the extent consistent with the Office of the Interconnection’s confidentiality obligations in … the Operating Agreement, related work papers to all new service customers that had new service requests evaluated in the study and to the affected transmission owner(s).”
The company said the scope of work outlined in the studies is “badly inflated and intended to defeat the TransSource network upgrades … making it difficult, if not impossible, for TransSource to secure the financing required for its network upgrades.”
TransSource added that its queue positions “directly affect numerous PJM Order 1000 Regional Transmission Expansion Projects, several of which stand to be rendered unnecessary if TransSource’s projects are completed and become operational.”
The complaint was filed by TransSource Manager Adam Rousselle, who did not return a request for comment.
The House on Wednesday voted 247-180 to weaken the Environmental Protection Agency’s Clean Power Plan. The bill would delay implementation of the carbon emissions rules for power plants and would allow states to opt out of the rules.
“The bill’s effects would be felt hardest by those most at risk from the impacts of air pollution and climate change, such as the elderly, the infirm, children, native and tribal groups, and low-income populations,” the White House said in a letter to lawmakers. It promised that President Obama would veto the bill if it reached his desk.
Senate Republicans have introduced a similar bill that would go even further to weaken the rule and impair the EPA’s ability to set carbon rules for power plants.
Federal Judge in Wyoming Grants Temporary Stop to Fracking Rules
Skavdahl
A district court judge in Wyoming last week granted a request to temporarily stop new federal rules governing hydraulic fracturing on public lands.
Judge Scott Skavdahl granted a reprieve until July 22, acting on a request from the oil and gas industry, which said the rules represent an “arbitrary and unnecessary” burden on drillers. Industry was joined by state governments in Colorado, Wyoming, North Dakota and Utah in stopping the new rules.
The rules would require companies to disclose chemicals used in fracking on federal land and to implement new practices to curb oil and gas leaks.
DOE Approves Sabine Pass LNG Export Expansion Plan
The Department of Energy on Friday approved Cheniere Energy’s plan to expand its Sabine Pass liquefied natural gas terminal in Louisiana to export LNG to countries that do not have free trade agreements with the U.S. Cheniere already has four production facilities nearing completion at the terminal. The approval authorizes it to build two more.
The government’s approval came two days after the Federal Energy Regulatory Commission declined a request by the Sierra Club to reconsider its approval of the expansion plans.
The development of new domestic gas fields has transformed the nation’s energy outlook, allowing the industry to promote exports where a decade ago it had been planning to increase imports of LNG to buttress U.S. supplies. The Sabine Pass terminal will be the first large-scale plant in decades to ship LNG from the continental U.S.
FERC Denies Request to Extend Public Comment Period on Mountain Valley
The Federal Energy Regulatory Commission has turned down a request to expand the public comment session for a proposed natural gas pipeline that would run through central Virginia. Lawmakers and other officials asked for an extension of the comment period, but FERC Chairman Norman Bay declared the session ended.
The 300-mile Mountain Valley pipeline would transport natural gas from Wetzel County, W.Va., to Pittsylvania County, Va.
NRC Steps up Oversight at Talen’s Susquehanna Site
The Nuclear Regulatory Commission will increase its oversight of Talen Energy’s Susquehanna nuclear station in Pennsylvania after a recent inspection during an emergency drill identified weaknesses with the plant’s response. Talen Energy was formed by the recent spinoff of PPL’s generation assets.
The problem involves the plant’s interpretation of when to start a 15-minute clock for an emergency assessment of a radioactive leak. Plant personnel thought the clock started when it was determined that crews were unable to stop a leak. But NRC rules say the clock starts when a leak is first detected.
“It’s important during an emergency situation that state, county and local officials are provided with information in a timely manner to assess the situation and implement protective actions, if warranted,” NRC Region I Administrator Dan Dorman said in a news release. “While the probability of an event of this magnitude is extremely low, this finding points to a weakness in that area that the company will need to address.”
DOE Study Finds Canadian Oil Sands Give off Increased Greenhouse Gases
A study funded by the U.S. Department of Energy found that petroleum extracted from Canadian oil sands produces 20% more greenhouse gases than conventional crude. The findings are consistent with long-held assumptions about oil sands production, which requires more energy to extract than conventional oil.
The study, conducted by the department’s Argonne National Laboratory, Stanford University and the University of California, noted that oil sands production is expected to double in the next 15 years, and that half of that crude could end up in the United States.
The findings are expected to fuel debate on the Keystone XL Pipeline, which is designed to transport Canadian crude to oil refineries in the Gulf of Mexico region. Final approval of the pipeline has not yet been granted.
FERC to Prepare Impact Statement for Port Arthur LNG Project
The Federal Energy Regulatory Commission has issued a notice of intent to draw up an environmental impact statement for the proposed Port Arthur Liquefaction Project in Texas, as well as an associated pipeline project.
Port Arthur LNG, an affiliate of Sempra LNG, and Port Arthur Pipeline, a subsidiary of Sempra US Gas and Power, are planning to construct and operate interrelated LNG terminal and natural gas infrastructure projects along the Sabine-Neches Ship Channel in Jefferson County, Texas.
The Port Arthur Pipeline Project includes 35 miles of pipeline to supply the export terminal. Part of an existing state highway and as many as five existing pipelines will need to be relocated as part of the project.
WILLIAMSBURG, Va. — Dominion Resources CEO Tom Farrell spoke of the challenges of social media, the promise of utility-scale solar and the dangers of “magical thinking” in remarks to the 20th annual Education Conference of the Mid-Atlantic Conference of Regulatory Utility Commissioners last week.
Farrell
“Transitioning from more than three decades of public policy centered on the notion of energy scarcity to energy abundance is a very good problem to have, but nevertheless it’s a problem,” Farrell said. Making the transition, he said, will require new gas and electric infrastructure and a rational response to environmental regulations.
“The combined effect of the proposed climate change, air quality, water quality, ash disposal and many other [energy-related] regulations on customer costs and reliability is a great cause for concern … But wishing away regulations we might differ with is not an option,” he said.
“We must avoid magical thinking in the public policy arena — the type of thinking that bypasses the laws of physics, the limits of technology and the realities of human nature in pursuit of ideological goals. Just as we have long recognized that hope is not a business plan, so we must accept that ideology is not an energy policy.”
Farrell said he expects utility-scale solar to be part of the response to the Environmental Protection Agency’s Clean Power Plan. “Although much of the public policy debate and all of the publicity tends to focus on distributed solar, the real story has been the explosive growth in utility–scale solar, by far the most cost-effective … and useful complement to traditional generation,” he said.
Farrell praised Federal Energy Regulatory Commission Chairman Norman Bay’s suggestion earlier in the conference that states create “energy corridors” for siting both electric and gas lines.
Meeting future environmental rules, Farrell said, will require utilities to overcome obstacles from both infrastructure opponents and federal agencies responsible for approving siting of new lines.
“Social media … accelerates the flow of information — and misinformation — on the Web. In the hands of those who oppose new energy infrastructure, social media gone viral can erode industry’s credibility and make our job of communicating facts much harder. But communicate we must. Our industry has not always been on the cutting edge in the use of social media tools. But we’re going to have to learn how to do it and we’re going to have to learn how to respond.”
Farrell said utilities are facing an unusual alliance of “environmental groups who don’t want any fossil fuels used at all” and Tea Party-type activists who “say I’m happy to use gas or electricity, but I don’t want you doing it on my property.”
“When you put those two together that’s a very interesting coalition,” he said. “I think you’re going to see … that grow exponentially over the next five years.”
He expressed frustration with what he said were seemingly contradictory directives from federal agencies, citing the difficulty Dominion has had in winning federal approval for a transmission line across Virginia’s James River. The line is needed because of the loss of coal-fired generation shuttered due to environmental rules. “We still don’t have all the permits and we’ve been working on it for six years,” he said.
“We would do well to acknowledge that energy issues are highly complex, that there are tradeoffs and opportunity costs embedded in every single policy decision made. There is no silver bullet solution that’s going to solve all the problems and do it reliably and inexpensively,” he said. “In essence this means more hard work on energy policy and less attention paid to energy soundbites coming from the fringes on either side.”
FirstEnergy officials confirmed that the soon-to-be retired R.E. Burger power plant in Eastern Ohio could be the site of an ethane cracker plant if it reaches a deal with two foreign chemical companies. The news came when FirstEnergy Generation President James Lash said the company is moving a machine shop from the Burger site to Canonsburg, Pa.
The cracker plant would convert ethane produced from the Utica and Marcellus Shale formations into material used by plastics and petrochemical manufacturers Marubeni Corp., of Japan, and PTT Global Chemical Public Co., of Thailand.
Columbia Pipeline Spending $2.7 Billion on Shale Gas Transport
Columbia Pipeline Group plans to invest $2.7 billion in natural gas transmission projects to transport production from the Marcellus and Utica shale regions in Appalachia to the Gulf Coast.
Columbia’s Mountainer XPress and Gulf XPress will add capacity to deliver 2.7 bcf/d from shale areas in Ohio, Pennsylvania and West Virginia. The Mountaineer XPress project involves 165 miles of new pipeline, while the Gulf XPress project includes upgrades to existing infrastructure between Kentucky and Louisiana.
The Houston-based Columbia is a subsidiary of NiSource.
Sunny Days Mean Less Stink in Detroit Thanks to Bigbelly
Detroit is becoming the latest city to use the solar-powered Bigbelly sidewalk trash compactors.
DTE Energy will install seven of the trash-compacting and recycling units in several Detroit locations as part of its Energize Detroit neighborhood revitalization program. The idea is to eliminate trash overflows, keep insects away and beautify neighborhoods. The solar units will automatically send signals to collection trucks when they are full.
Bigbelly says its units are operating in 47 countries and that Philadelphia has installed about 1,000 of the devices.
SPS Case Spurned by New Mexico Commission over Detail
The New Mexico Public Regulation Commission has dismissed Southwestern Public Service Co.’s latest rate case filing, which would have increased base rates by $1.4 million in mid-2016.
The commission said SPS did not comply with its new interpretation of a statute involving forecasted test year (FTY) periods, according to a regulatory filing by SPS’s parent, Xcel Energy. SPS said it plans to refile the rate case later this year.
Energy Future Holdings Calls off Oncor Auction Plans
Energy Future Holdings, 80% owner of transmission company Oncor, has told a Delaware Bankruptcy Court judge that it is calling off the planned auction of its ownership stake and will go ahead with a reorganization plan.
The Texas energy giant filed for Chapter 11 bankruptcy protection in April 2014, saddled by debt. It announced last year that it was giving up on its original restructuring plan and would auction off its Oncor stake, which is valued at about $19 billion. NextEra Energy and Hunt Consolidated Inc. were identified as likely bidders.
But Energy Future says it will now return to Plan A and reorganize. It plans to emerge from bankruptcy next year.
Microsoft founder Bill Gates, who says he has already invested an estimated $1 billion in renewable energy companies, plans to double his investment within the next five years.
Gates has concentrated his green investments in energy storage, advanced nuclear and carbon capture technologies.
He said it is time for such companies to push the envelope to develop new methods to bring renewable energy to market. “Power is about reliability,” he said. “We need to get something that works reliably.”
Duke Energy is divesting its stake in a five-year-old rooftop solar joint venture with Integrys Energy Systems.
Duke is selling its 9-MW share of the 32-MW venture to TerraForm Power, of Maryland. TerraForm had already purchased the other 23 MW from Integrys. Together, Duke and Integrys invested about $180 million in a variety of small solar projects. It marked Duke’s first venture into solar.
NextEra Energy Looking for New Wind Site in North Dakota
NextEra Energy Resources, which in May withdrew an application to build a $250 million wind farm in North Dakota, announced it is looking for sites for a similar plant.
Although the company won’t give details on sites it is considering, a member of the Public Service Commission said the company is not looking far from the location of its first project.
“NextEra has informed us they’re looking at multiple locations and all of those locations are south of where they were looking at before,” Commissioner Brian Kalk said. The first plan was shelved after landowners objected and the Stark County Commission denied the company a conditional use permit.
Joe Dominguez, executive vice president of government and regulatory affairs for Exelon, said the company is not abandoning organized markets but needs them to reflect the cost of carbon emissions for its nuclear fleet to survive.
“The work that we’ve seen from the RTOs — from PJM, even from ERCOT — indicate that with a relatively modest price on carbon we can achieve compliance with the EPA’s [Clean Power] Plan.”
Dominguez said he believes EPA will get the nuclear issue “half right” in the final emissions rule, due this summer.
“My guess is EPA is going to largely ignore the problem and hope that nuclear plants don’t retire,” he said.
But he predicted that EPA will “give substantial incentives for mass-based regional cooperative programs to achieve compliance.”
“And there, I think, nuclear is going to be fully recognized, because in any mass-based program the loss of nuclear units would quite obviously be reflected in an increase in the emissions as fossil fuel takes up the gap left by nuclear. That will self-correct.”
MISO stakeholders have submitted recommendations for refining the out-of-cycle request process in the wake of transmission developer complaints over Entergy’s $187 million transmission upgrade near Lake Charles, La.
MISO approved the OOC request, which Entergy said was necessary to meet the sudden needs of an industrial customer, following a clamor from transmission developers complaining they were denied a chance to compete for the project. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)
Transmission developers, transmission owners and ITC Holdings proposed numerous changes to MISO’s Transmission Planning Business Practices Manual. “The urgency and the need cannot be the result of inadequate planning, or worse, action that attempts to circumvent the robust, stakeholder-driven process” in the MISO Transmission Expansion Plan (MTEP), the TD sector said in comments submitted at a Planning Advisory Committee meeting.
Among the sector’s proposed changes is a requirement that OOC projects involving multiple load additions have “documented customer service requests.” One of the criticisms of the Entergy OOC request was that neither MISO nor stakeholders were privy to details about the Entergy customer or its specific load needs.
Entergy pointed broadly to an industrial renaissance in the Lake Charles region and said that it received unanticipated customer demand for service after the annual MTEP cutoff date. It said it was not permitted to disclose the customer.
The TD sector also proposed to insert language that would require MISO, before submitting a request for stakeholder review, to determine that a project “does not directly or indirectly eliminate the need for a Market Efficiency Project or Multi-Value Project” — projects that are subject to competition.
More Flexible Language
Meanwhile, TOs are seeking to tweak OOC eligibility rules. They proposed language that notes that “it is not possible to predict every event that will lead to the need for OOC treatment” of a baseline reliability project or “other” project. For example, projects may be driven by generation retirements or regulatory mandates, they said.
ITC Holdings, which did not join with the majority of transmission owner comments, also proposed to change the criteria for OOC project designation. ITC said its language change would allow for needs not specifically identified in the existing criteria. “For example, storm damage that necessitates a system change may require OOC review,” ITC said.
Alternatives to OOC
Other changes proposed for the Transmission Planning Business Practices Manual involve stakeholder reviews of OOC requests.
The TD sector complained that MISO moved too fast on Entergy’s Lake Charles request, without adequate feedback from stakeholders.
The sector is seeking at least one sub-regional planning meeting or public Technical Studies Task Force meeting “at which the out-of-cycle project and identified alternatives will be evaluated.” Stakeholders would be able to submit alternatives to an OOC at a following sub-regional or task force meeting.
TOs Assert Rights
At the PAC meeting last week, MISO officials attempted to compare the suggested stakeholder redlines to the BPM manual. Stakeholders offered some additional perspective.
“What we were trying to do is return this BPM language to its fundamental source, which is the transmission owner’s agreement,” said Cynthia Crane, principal regulatory analyst at ITC Holdings.
“And that’s what’s missing in all this dialog, it’s [that] the transmission owners agreement gives transmission owners certain rights” such as to upgrade, modify, alter or replace its facilities, she said. “We have to be really careful in what we are drafting here in order to not violate the TOA,” she added.
Jeff Webb, director of planning at MISO, said “The last thing you want to do is impede the TOs’ [ability to meet their] obligations.”
Suspicion of OOC Requests
But some speaking at the PAC meeting urged MISO to be vigilant about maintaining oversight, given the potential for utilities to misuse the OOC process.
“I can play this game all day where I need to build [a line] because I haven’t put my load in for three years now and I know it’s coming, but I don’t want to go through that competitive process stuff,” said Kip Fox, director of transmission strategy and grid development at American Electric Power, speaking of a hypothetical abuse. “So I’ll just wait until the four-year window closes and then I’ll submit it and all of the sudden it’s a reliability project.”
Fox told MISO: “You have to give us some confidence that those loads are being looked at.”
Webb noted the challenge in obtaining information from a load-serving entity making an OOC request. “What is the load-serving entity able and willing to disclose to defuse this sort of ‘proof issue’ that’s in front of us?”
Load-serving entities often counter that they’re prevented by nondisclosure agreements from revealing specifics about customer expansion plans.
Webb said MISO would review the feedback and return at a future meeting with draft language of its own.
PJM doesn’t plan to allow generators to make hourly market offers for winter 2015/16, despite a Federal Energy Regulatory Commission order that such flexibility be developed by Nov. 1.
Officials said the RTO cannot accept such offers until it revamps its market system and that the new software cannot be completed by next winter.
In its June 9 ruling, FERC ordered PJM to file Tariff changes allowing market participants to submit day-ahead offers that vary by the hour and update their offers in real time, including in emergency situations, or explain why the changes are unnecessary. The commission said the changes should take effect by Nov. 1 “or as soon as practicable thereafter.” PJM must make a compliance filing informing the commission of its plans by July 10. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)
In April, stakeholders approved the creation of the Generator Offer Flexibility Senior Task Force to consider such changes in response to a problem statement by Calpine. Calpine noted that PJM is the only organized market in the country that doesn’t permit generators to vary their offers hourly. (See Bid for Generator Price Flexibility Draws Debate over 10% Adder.)
PJM said it considered proposing an interim solution while it waits for the software changes but bowed to stakeholder sentiment for a single, long-term solution.
The Independent Market Monitor is recommending a broader look at concerns that PJM is buying too much fast-responding “RegD” resources in the regulation market. The Monitor said Thursday that stakeholders should revisit the marginal benefit factor that defines the substitutability between “RegA” and RegD megawatts.
“PJM’s current marginal benefit factor function is, at least in some hours, overvaluing RegD as a substitute for RegA in the optimization,” said Howard Haas of Monitoring Analytics. The misalignment also means RegD resources are being incorrectly compensated — sometimes being paid too little, and sometimes too much, Haas said. (See PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation.)
PJM introduced its own problem statement on the regulation issue at the April Operating Committee meeting, but it has not yet been brought to a vote. Under times of system stress, PJM said, it has observed issues with regulation performance when the proportion of megawatts from RegD resources is greater than 42%. (See “Too Much of a Good Thing? PJM Concerned Fast Response Regulation Crowding out Traditional Resources,” PJM Operating Committee Briefs.)
A PJM official told the MRC that the RTO is currently performing a study on the issue, which will take eight weeks to complete.
Changes Would Allow Earlier Replacement Transactions
The committee will be asked to vote at its July 23 meeting on manual changes that would allow market participants to enter replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year if the need is linked to a physical reason that would prevent a participant from meeting its commitment.
Such replacements would be permitted when the owner of the replaced resource could show the expected final physical position of the resource at the time of the request.
Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project is cancelled or delayed. Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.
Resources replaced would not be able to be recommitted for the delivery year.
PJM Law Proposes Cleaning up Language in Governing Documents
The PJM Law Department proposed an initiative to clean up language in the RTO’s governing documents that is “ambiguous, incorrect or requires clarification.”
The project would entail reviewing the Tariff, Operating Agreement and Reliability Assurance Agreement related to topics including offer caps and prices, demand resources and the capacity market.
PJM’s proposed problem statement and issue charge would assign the task to the Market Implementation Committee, separating it from the effort already underway involving the Tariff Harmonization Senior Task Force. The task force was formed in December to identify discrepancies in provisions regarding definitions, indemnification, limitation of liability and alternative dispute resolution procedures in the same governing documents. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)
Ed Tatum of Old Dominion Electric Cooperative suggested that PJM consider unifying the efforts, saying ODEC wanted to participate but had limited resources. “Words do matter,” he said. “Anytime we do something like this, it’s a big deal.”
“I didn’t think what we were trying to do here really fit” the task force’s charter, responded PJM attorney Jacqui Hugee, who added the charter could be changed.
The task force plans to bring its first batch of changes to the next MRC meeting for a vote, along with a second batch for first reading.
Changes to Manuals 03, 3A, 19 Endorsed
Members endorsed the following manual changes:
Manual 19: Load Forecasting and Analysis. Makes changes to residential measurement and verification rules. Provides a solution for the issue that some electric distribution companies (EDCs) are prohibited from sharing personally identifiable information about residential customers participating in demand response programs. EDCs may use unique ID numbers instead through May 31, 2016.
Manual 03: Transmission Operations. Requires a separation between emergency and load dump ratings. In the event they are the same, the emergency rating submitted by the transmission owner shall be, at a minimum, 3% lower than the submitted Load Dump rating. If this change results in a normal rating that is higher than the long-term emergency rating, the TO shall, at a minimum, make the normal rating equal to the LTE rating.
Manual 3A: Energy Management System Model Updates and Quality Assurance. Continues effort to streamline and update sections pertaining to model updates. Most significant change is new section added on sub-transmission model submission requirements. TERM Appendix A reworked to more clearly outline business rules and tool interaction.
