Page 1616 – RTO Insider

August 22, 2016

Skeptics Question CAISO Plan to Lower Bid Floor

By Robert Mullin

Critics of a proposal to lower CAISO’s energy market bid floor last week questioned the need for the measure and its efficacy in solving the ISO’s increasing intervals of oversupply.

The ISO contends that reducing the bid floor from -$150/MWh to -$300/MWh will provide the market with more “downward flexibility” — or the ability to curtail renewable resources in the market rather than through out-of-market operations.

CAISO hopes that lowering the bid floor will persuade self-scheduled resources to submit bids that reflect the marginal cost of operations when oversupply turns prices negative.

“To ensure the ISO is able to provide accurate price signals to incent a more flexible fleet of resources during this transition, market changes must be implemented to encourage generators to economically participate in the markets rather than self-schedule,” CAISO wrote in its proposal.

Self-schedules often represent renewable resources operating under power purchase agreements with load-serving entities that include take-or-pay clauses. The LSE’s penalty for refusing the power adds to its opportunity cost of not generating a renewable energy certificate (REC).

The ISO has authority to curtail self-scheduled deliveries to protect reliability during periods of oversupply. The ISO said it was compelled to take that step during 2.5% of five-minute intervals between April 2015 and April 2016.

CAISO is seeing an increase in curtailed self-schedules as more renewables come online in California.

The practice is only growing with the increased penetration of renewables in response to the state’s 50% by 2030 renewable portfolio standard.

“In April [2016] alone we had 11% of intervals where self-schedules were being cut,” Kallie Wells, senior market monitoring analyst in CAISO’s market infrastructure and development department, said during an Aug. 18 stakeholder call. “The shoulder months will likely see increased amounts of that.”

In addition to incentivizing LSEs to bid contracted renewable resources into the CAISO market rather than self-schedule, ISO staff say they also hope the change will encourage LSEs to negotiate renewable PPAs that give them the option to curtail renewables to accommodate the ISO’s operational needs.

Market Monitor not Convinced

CAISO’s internal Market Monitor says the ISO hasn’t made a compelling case.

The Department of Market Monitoring “is right now opposed to lowering the bid floor,” said Ryan Kurlinski, manager of the department’s analysis and mitigation group. “We’re not seeing the evidence that this policy will create additional decremental bids.”

Kurlinski contended that lowering the bid floor will create a greater likelihood for the exercise of market power in decremental bids and expand the opportunity for increasing bid-cost recovery — or uplift — payments, which are shared by load across the ISO.

While a number of stakeholders have commented in favor of the measure, others are skeptical.

“Can you tell me what type of resource would be bidding in at less than -$150/MWh?” asked Eric Little, manager of wholesale market and greenhouse gas market design at Southern California Edison.

“We did look into actual costs, and -$150/MWh did cover a portion of intermittent resources’ costs but didn’t cover another portion,” said Brad Cooper, CAISO’s manager of market design and regulatory policy.

“Whenever we talk about this it comes down to RECs, but there are no RECs worth more than” $150/MWh, Little said.

Greg Cook, CAISO director of market and infrastructure policy, said that “it comes down to the power purchase agreements.”

“We do know that there are those that have contracts that are take or pay, but those contracts are changing,” Little said. “Are you trying to get companies to renegotiate contracts?”

Seeking Evidence

Little also asked the ISO to provide more evidence supporting the change.

“I would like to see something that would show what elements will require a floor below -$150,” he said. “That would help us out.”

Nivad Navid, a principal with Pacific Gas and Electric, also sought more supporting data, asking CAISO to provide statistics showing how often the market clears at -$150/MWh. He also expressed concern about the ISO deterring LSEs from submitting self-schedules.

“We’re not saying you can’t self-schedule,” Wells said. “By lowering the bid floor, economic bids will more likely set the price” rather than out-of-market mechanisms. Wells also said a deeper pool of economic bids would prevent the ISO from cutting self-schedules.

“So when you change the bid floor, are you expecting that you will not need any more curtailment?” Navid asked.

“It sounds like the assumption you’re making is that there are resources that can’t bid into the market because of the bid floor of -$150,” said Josh Arnold, a settlement analyst at PG&E.

“That seems to be a sticky assumption to be making without providing supporting data,” he continued, adding that the ISO’s Board of Governors had previously said the -$150/MWh floor was appropriate.

Arnold questioned whether the renewables-heavy fleet serving California would change its market behavior as a result of the change, pointing out the difficulty in renegotiating contracts within the timeline of the proposal’s implementation. The ISO plans to seek approval from the board this fall, meaning the change could be implemented early next year, pending FERC approval.

“I’m very confused by the way you’re going about this,” Arnold said. “It seems like you’re anticipating an upcoming problem and trying to smash it with a hammer.”

CAISO is pairing the bid floor proposal with a plan to no longer exempt load corresponding with self-scheduled supply from being allocated costs associated with uplift payments. The ISO says the latter proposal will further incentivize economic bids over self-schedules and align allocation with cost-causation principles, as self-scheduled generation is also contributing to the oversupply issue.

The ISO is seeking comments on both proposals by Aug. 25 and plans to present a final plan to the board in October.

August 21, 2016

Co-ops, Munis Call for Reset of PJM Capacity Model

By Rory D. Sweeney and Rich Heidorn Jr.

The grand bargain that created PJM’s capacity market in 2007 has suffered fissures in the years since because of repeated rule changes.

Now, a coalition of cooperatives and municipal utilities says it’s time to start over.

At this week’s Markets and Reliability Committee meeting, American Municipal Power plans to propose a problem statement calling for a “holistic assessment” of the Reliability Pricing Model.

Joining with AMP are the Delaware Municipal Electric Corp., Old Dominion Electric Cooperative, the PJM Public Power Coalition and the Public Power Association of New Jersey.

Also part of the coalition are the dominant utility in PJM’s largest vertically integrated state, Dominion Virginia Power, and retailer Direct Energy.

Although the initiative is likely to be greeted coolly by many, it has a good chance of winning the majority support needed to proceed because PJM stakeholders rarely reject problem statements.

But how AMP and its supporters would build a larger coalition to replace the RPM — or what that replacement would look like — is far from clear.

Winning approval for Tariff changes would take a two-thirds sector-weighted vote at the MRC and Members Committee. The current coalition includes 31 of 43 members of the Electric Distributors sector but only one of 13 Transmission Owners, one of 353 Other Suppliers and none of the 23 End Use Customers or 90 Generation Owners.

PJM’s public power members have long complained that they could meet their capacity needs more cheaply through self-supply than through the RTO’s capacity auctions. AMP said the restoration of public power systems’ ability to self-supply is a “minimum step to reform the capacity construct.” (See Capacity Market Attracts Praise, Criticism at FERC, “APPA, ISO-NE Spar on Capacity Markets,” NARUC 2016 Winter Meetings Briefs.)

Neither the problem statement nor the proposed issue charge suggests any broader solution.

But in a press release quoting from her comments at PJM’s Grid 20/20 conference Thursday, Lisa McAlister, AMP’s deputy general counsel for FERC/RTO affairs, outlined some options.

“PJM could still specify resource adequacy requirements for its footprint and local distribution companies of concern. The load-serving entity or electric distributor would be responsible for securing its peak load obligation plus a predetermined reserve margin and would face significant penalties absent securing the capacity,” McAlister said. “These LSEs/EDs could procure bilaterally resources on a long-term portfolio basis in compliance with a state’s resource adequacy requirements. PJM could conduct a residual auction to accommodate supply that did not enter into a long-term arrangement.”

The RPM, which took effect June 1, 2007, replaced PJM’s voluntary Capacity Credit Market, which produced less than 10% of PJM’s total capacity obligation. It was based on daily market clearing prices that were uniform across the RTO’s footprint.

The “original CCM did not include explicit market power mitigation rules, provided only weak performance incentives and did not permit the participation of demand-side resources,” according to a 2008 report by The Brattle Group. Prices were generally below the cost of adding new capacity and did not recognize the higher value of capacity in import-constrained areas in eastern PJM.

FERC ordered PJM to develop a replacement in April 2006.

The RPM, the product of more than two years of stakeholder negotiations, introduced the three-year forward auction with a downward sloping demand curve, locational pricing and included stronger performance incentives and market power protections. It allowed direct participation of demand-side resources and mandated participation by load.

More than 65 parties took part in FERC-mediated settlement discussions that resulted in the December 2006 RPM order (ER05-1410-001, et al.).

In the years since, AMP and its allies say, the RPM has proven it lacks the resilience to accommodate “unforeseen events.”

AMP counts “24 significant filings” to modify the RPM since 2010. “According to PJM, the 2016 [Base Residual Auction] was the first BRA with no rule changes from the prior year,” the problem statement says.

pjm capacity performance — The Capacity Performance model was designed to avoid the outages experienced during the polar vortex.

The new Capacity Performance construct was a reaction to the January 2014 polar vortex, when forced outages exceeded 20% and PJM nearly fell short of meeting its load. CP pays generators bonuses for fulfilling their delivery commitments when the system is stressed and charges them increased penalties when they fail to perform as agreed.

Opposed by environmentalists and demand response supporters for its phase out of summer-only resources, it’s the subject of a challenge before the D.C. Circuit Court of Appeals.

AMP says the RPM continues to be beset by threats such as the subsidies FirstEnergy and American Electric Power have sought for their money-losing plants in Ohio. EPA’s Clean Power Plan could provoke further changes, AMP says.

The proposed Ohio subsidies have spawned calls to extend the minimum offer price rule — currently applied only to new gas-fired generators entering the capacity auction — to existing units.

McAlister said that would be a mistake. “Public power does not want to be a source of increased capacity prices as a result of being considered subsidized because we have a lower cost of equity than an administratively determined reference resource,” she said.

“Capacity Performance was particularly stressful to the stakeholder community due to the inclusion of operational performance requirements, a paradigm shift for seasonal resource participation and a near complete unwind of the market mitigation rules surrounding offer caps, all of which were enacted in an expedited timeframe,” the problem statement says. “PJM needs a resource adequacy construct that is sufficiently robust to be reasonably able to withstand unforeseen exogenous events absent significant and reactionary rule change.”

The issue charge proposes that work on the overhaul be performed by a new Capacity Market Construct Restructuring Senior Task Force reporting to the MRC. The group hopes to complete the work by the end of the third quarter in 2017.

McAlister suggested the effort could be successful even if the group doesn’t win a complete overhaul.

“While the PJM stakeholder process attempts to achieve consensus, it also … provides an opportunity for minority views to be heard and ultimately enables the PJM board to be better informed as it decides how best to proceed.”

August 18, 2016

Arkansas Landowners Seek to Stop Plains Eastern Clean Line Project

By Tom Kleckner

Two Arkansas landowner groups have filed suit to block Clean Line Energy Partners’ planned 700-mile HVDC transmission line, questioning the legality of the project’s approval and its right to use eminent domain (3:16-cv-00207-JLH).

The groups, Golden Bridge and Downwind, filed their complaint Aug. 15 in U.S. District Court in Jonesboro, Ark., listing the U.S. Department of Energy, Secretary of Energy Ernest Moniz and the Southwestern Power Administration (SPA) and its administrator, Scott Carpenter, as defendants.

In March, the Energy Department approved Clean Line’s $2.5 billion Plains & Eastern Clean Line project, which would deliver 4,000 MW of wind power from the Oklahoma Panhandle to the Tennessee Valley Authority near Memphis, Tenn. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)

congress, clean line project, plains & eastern clean line — Clean Line’s Plains & Eastern Clean Line Project *Source: Clean Line Energy Partners*

The department said it would participate in the project under Section 1222 of the Energy Policy Act of 2005 (EPACT), which authorizes it to take part in “designing, developing, constructing, operating, maintaining or owning” new transmission. The department will do so through SPA, a federal agency that markets hydroelectric power from 24 dams in six states.

The lawsuit questions the process by which the Energy Department approved the project, saying it acted “arbitrarily and capriciously” in giving “undue consideration to nonstatutory, policy considerations.” The landowners said the department and SPA approved the project’s construction and operation, “completely [ignoring]” existing Arkansas siting laws “and without the necessary approval of the appropriate Arkansas siting authorities.” They are asking the court to declare the federal agencies’ use of eminent domain in violation of EPACT and force the department to withdraw its approval of the project until it is in compliance with state-level siting requirements and federal laws, including the Fifth Amendment.

A Golden Bridge spokesman told local media the landowners should have been given a “significant opportunity to engage on a meaningful and substantive level.”

“Unfortunately, it is not uncommon to see legal complaints filed against the most important infrastructure projects,” Clean Line said in a statement. The Houston-based company called on the private and public sectors to “come together to bring new infrastructure projects to fruition.”

Clean Line said it has invested nearly $100 million of private capital in the project’s development and it expects to make more than $30 million in payments to Arkansas landowners for easements and building transmission towers on their property. It said it was “very confident” in Section 1222’s validity and the “extensive process” behind the Energy Department’s decision to participate.

The Plains & Eastern Clean Line project has also drawn opposition from Arkansas’ all-Republican Congressional delegation. Rep. Steve Womack advanced a bill in the U.S. House of Representatives in June that would amend EPACT to require approval from a state’s governor and legislators before using eminent domain. The state’s senior senator, John Boozman, has filed a matching bill that hasn’t moved since May. (See House Panel OKs Bill Targeting Clean Line Project.)

Clean Line expects to begin construction on the project as early as next year.

August 17, 2016April 2, 2025

UPDATED: Mass. Supreme Court Vacates EDC-Pipeline Contract Order

By Michael Brooks and William Opalka

Massachusetts’ highest court Wednesday struck down regulators’ plan to allow electric distribution companies to charge ratepayers for additional natural gas pipeline capacity, concluding that the legislature intended for electricity and gas utilities to be regulated separately (SJC-12051).

The Department of Public Utilities issued the order last year in response to the Department of Energy Resources’ request for an investigation into how the state could add more pipeline capacity, an issue that has lingered since the polar vortex of 2014. The order was challenged by ENGIE Gas & LNG and the Conservation Law Foundation.

massachusetts, electric distribution companies, natural gas pipeline

John Adams Courthouse, home of the Massachusetts Supreme Judicial Court. Source: Massachusetts

The Supreme Judicial Court determined that state law, dating back to 1926, precluded the DPU from allowing EDCs to enter into contracts for gas capacity.

The DPU argued that language in the 1926 act unambiguously allowed it to approve such contracts. But the court said that the law neither expressly prohibits nor permits the department’s order. Instead, it relied on legislative intent for its ruling.

“We conclude that the legislature did not intend to authorize the department to approve the contracts contemplated in its order, but rather intended, with limited exceptions, to regulate the gas and electric utilities differently,” the court said.

The court found that the law was enacted at a time when EDCs were being consolidated into large holding companies, provoking concerns about the impact on ratepayers. The 1926 law was amended in 1930 to include gas companies because lawmakers “predicted that the same concerns about electric companies would arise with respect to gas companies as well,” the court said. It also noted that the state’s utilities distribute both electricity and gas.

The court’s logic mirrors comments state Attorney General Maura Healey made in June before the order was finalized. “Legislative history also clearly demonstrates that the legislature meant to relate purchases of electricity to electric companies and purchases of gas to gas companies,” she wrote.

“The court’s decision makes clear that if pipeline developers want to build new projects in this state, they will need to find a source of financing other than electric ratepayers’ wallets,” she said in a statement Wednesday.

Healey also released a study in November disputing the presumption that New England needed additional pipelines to maintain reliability and lower prices. (See Mass. Attorney General’s Study: Pipelines Unneeded.)

Environmentalists praised the court’s decision.

The ruling “will help Massachusetts move more quickly to a clean, renewable energy future,” the Sierra Club said. “The $3 billion that would have gone to out-of-state corporations for fracked gas pipelines can now be spent here in Massachusetts on projects such as energy efficiency, energy conservation and clean power sources like solar and wind.”

The New England Coalition for Affordable Energy, which advocates for expanded energy infrastructure in the region, called the ruling disappointing, but not surprising.

“However, it does not resolve underlying concerns about the region’s ability to cost-effectively meet future needs, which we believe requires an integrated approach using both renewable resources and natural gas generation,” the group said.

While pipeline proponents were disappointed by the court’s ruling, they said they would press on with their attempts to get infrastructure funded and built.

“This leaves Massachusetts and New England in a precarious position without sufficient gas capacity for electric generation during cold winters. The lack of gas infrastructure cost electric consumers $2.5 billion during the polar vortex winter of 2013 and 2014,” said Creighton Welch, a spokesman for Spectra Energy, which is developing the Access Northeast project with partners Eversource Energy and National Grid.

“This is a disappointing setback for the project, which is designed to help secure New England’s clean energy future, ensure the reliability of the electricity system and, most importantly, save customers more than $1 billion annually on their electricity bills,” National Grid said in a statement.

“While the court’s decision is certainly a setback, we will re-evaluate our path forward and remain committed to working with the New England states to provide the infrastructure so urgently needed to ensure reliable and lower-cost electricity for customers,” Eversource said.

Part of that path is changing its Tariff to allow for targeted capacity releases from natural gas pipelines to be sold to natural gas-fired generators. That proposal, which has been opposed by some power generators, is pending before FERC. (See Utilities Seek OK for Gas Releases to Generators at Technical Conference.)

“Massachusetts has some of the highest electricity rates in the nation, and without additional gas capacities and a diverse energy portfolio, the trends will continue to rise over time,” said Peter Lorenz, a spokesman for the Massachusetts Executive Office of Energy and Environmental Affairs.

The Massachusetts ruling may have also killed a similar pipeline funding order in Maine. State regulators there last month approved ratepayer financing, provided other New England states followed suit. (See Maine PUC Endorses Gas Pipeline Contracts.)

For its part, ISO-NE reiterated it remains neutral on individual projects or how they are financed. But the RTO repeated its position that the region needs gas infrastructure to replace retiring generation and to help balance the increased penetration of intermittent renewable resources.

“The ISO has consistently stated, based on studies conducted for the ISO as well as our operational experiences as the regional power system operator, that we continue to see a need for natural gas infrastructure to ensure continued system reliability,” spokeswoman Marcia Blomberg said. “The need will continue to grow as the region transitions rapidly to a power system with decreasing amounts of coal, oil and nuclear power and increasing levels of renewable and distributed energy resources.”

August 16, 2016

Generators Balk at PJM Proposal on Fuel-Cost Policies

By Rory D. Sweeney

Stakeholders continue to react coolly to PJM’s proposed rules for generator fuel-cost policies, spending two and a half hours expressing their concerns at last week’s Market Implementation Committee meeting.

PJM has held three meetings in the past three weeks to explain the policy to stakeholders, several of whom said last week that the rules are more punitive than incentivizing. The RTO is due to make an interim compliance filing on the issue Aug. 16.

The rules have been revised so that sellers without approved fuel-cost policies are not required to submit cost-based offers. They can, however, submit negative price offers and are subject to the greater of their capacity resource’s deficiency charges or nonperformance charges — such as those from a performance hour assessment.

A seller would have 30 days to revise a rejected policy, during which time the seller would revert back to using a previously approved policy.

A seller deemed by PJM and the Independent Market Monitor to have violated its approved policy would be subject to a separate penalty. The amount would be calculated via a formula based on the unit’s capacity and the LMP at its bus. The penalties would begin five days after the seller is notified about the noncompliance.

The proposal has “significant problems and needs substantial rethinking,” said Monitor Joe Bowring, who distributed his own proposal that requires CP units that don’t have approved policies to make offers, but penalizes them in a way similar to the unit capacity/LMP formula.

“It sounds like one bad rule offset by another bad rule,” Bowring said of PJM’s proposal. “They all have unintended consequences. What that means is that the units aren’t going to offer in, which isn’t what you want. You want units to offer in.”

“Unless we’re just trying to find another way to penalize a generator, can we please rethink this?” asked Jason Cox of Dynegy. Instead, the lost opportunity created by holding sellers to a $0 offer “seems like a pretty efficient way to get them to get a policy done,” he said.

pjm, fuel-cost policies — Natural gas plants in PJM’s energy market, such as Duke Energy’s 620-MW Buck Combined Cycle Station in Rowan County, N.C., would be subject to the RTO’s rules on fuel-cost policies. *Photo Source: Duke Energy*

Stakeholders felt the policy lacked clarity. Bob O’Connell of Main Line Electricity Market Consultants said that it has no way to maintain compliance, no procedure for making necessary revisions while maintaining compliance and no timeline for that process.

Ed Tatum of American Municipal Power said stakeholders have expressed “grave concerns” that “this penalty is overly punitive, goes beyond the scope of the order and is generally bad market design.”

Under the proposal, if the Monitor disagreed with a PJM-approved policy, it could refer it to FERC’s Office of Enforcement.

That, said Tatum, is “unacceptable.”

The purpose of the policy is twofold, Bowring explained: to ensure compliance with all requirements to participate in the PJM market and that offers are consistent with competitive offers. Sellers need to document a verifiable and systematic method for calculating cost-based offers, he said.

“There has to be recognition that we’re changing the paradigm about fuel-cost policies; it makes sense to give everyone enough time to get there, but there have to be incentives to get there so people are not simply wasting time [and] everyone’s working toward that same objective,” he said.

Stakeholders questioned how the policies would be reviewed and whether the process or the result was the real focus.

“I’m just hopeful that in the final language, that we’re talking about the reasonableness of the process, not the reasonableness of the result and that that’s really clearly articulated to everybody,” said Mike Borgatti of Gabel Associates.

The proposal is scheduled to be brought to votes by the MIC, along with the Markets and Reliability and Members committees next month, with board approval targeted for October before a filing with FERC.

August 15, 2016

NC Health Official Resigns in Dispute with Gov. over Duke Energy Coal Ash

By Ted Caddell

CHAPEL HILL, N.C. — A dispute between North Carolina’s governor and a veteran state scientist over Duke Energy’s coal ash practices has exploded into the public, with the scientist’s boss resigning in protest.

GovPatMcCrory (McCrory) - Duke Energy, Coal Ash — McCrory *Source: North Carolina State Gov.*

The state epidemiologist, Dr. Megan Davies, resigned Wednesday night, after Assistant Environmental Secretary Tom Reeder and state Health Director Randall Williams posted a statement criticizing her staffer’s concerns. The statement said toxicologist Ken Rudo’s “questionable and inconsistent scientific conclusions” had “created unnecessary fear and confusion among North Carolinians.”

Last year, Rudo balked at putting his name on a letter downplaying the risk of groundwater contamination near Duke power plants, despite being pressured by higher-ups in a meeting that he said included Gov. Pat McCrory, a Republican and former Duke Energy executive. McCrory has denied taking part in the meeting.

In her resignation letter, Davies was blunt. “I cannot work for a department and an administration that deliberately misleads the public,” she wrote.

McCrory and his administration have been dogged by the Duke coal ash issue since February 2014, when a dike at a retired Duke plant burst, releasing 39,000 tons of toxin-laden coal ash and 27 million gallons of contaminated water into the Dan River.

The dispute became public this month after a judge released portions of a deposition Rudo gave in a lawsuit by the Sierra Club, the Southern Environmental Law Center and other environmental groups over Duke’s coal ash storage sites. The suit alleges that toxins from coal ash stored on Duke sites are contaminating rivers and other waterways and groundwater. It calls on Duke to safely remove the coal ash and ensure residents living near the plants have clean water.

By the end of the week, Democrats in the state legislature were calling for a probe into the whole affair.

Meeting with the Governor

In his deposition, Rudo testified his office sent a warning to about 400 homeowners near Duke plants in late 2014, telling them their well water wasn’t safe to drink because of pollution from Duke’s coal ash.

Rudo said groundwater samples showed increased levels of hexavalent chromium and vanadium, both cancer-causing agents. As a result, while the issue was still being debated by Duke and other state environmental and health officials, Duke began supplying some of the homeowners with bottled water.

Duke Energy, Coal Ash — Duke Energy engineers and consultants view the breach at Dan River coal ash storage pond in 2014. *Source: North Carolina Department of Environmental Quality*

Rudo said that in early 2015, he was called in to a discussion with Reeder and other higher-ups about the wording of the letters. “They wanted language put on there that stated, in essence, we were overreacting in telling people not to drink their water,” Rudo said in the deposition. He said he objected to the wording and told them to take his name off the letter.

“You know, I can’t stand behind that,” he said. “It is just not right. It is going to confuse people. People are not going to really know whether they should drink the water or not,” Rudo testified.

The dispute came to a head, he said, when he was called to another meeting with a McCrory aide in March 2015 in which McCrory briefly took part by phone. “I have never talked to a governor in all of the years I have been here, so I was a little … intimidated,” he said.

Rudo said McCrory and the aide raised concerns about the department warning people not to drink the water.

The language on the letters was changed, and the revised letter was sent out while he was on vacation. “And it was just amazingly misleading and dishonest language,” Rudo said.

In May 2015, EPA fined Duke $102 million for federal Clean Water Act violations; North Carolina added a $6.6 million penalty.

Following public outcry, North Carolina legislators passed legislation calling for Duke to clean up all of its coal ash dumps in the state.

McCrory, who had worked for Duke for almost three decades before becoming governor, vetoed the bill in June 2016. Last month, he signed a compromise bill calling for Duke to begin cleaning up half of its coal storage sites immediately while monitoring the rest.

Deposition Becomes Public

The dispute became public last week after the Southern Environmental Law Center filed Rudo’s redacted deposition in the group’s lawsuit.

The McCrory administration fired back. “We don’t know why Ken Rudo lied under oath, but the governor absolutely did not take part in or request this call or meeting, as he suggests,” said McCrory’s chief of staff during a rare, late-night press conference.

When Rudo stood by his testimony, the administration issued a scathing statement Aug. 9.

“Rudo’s unprofessional approach to this important matter does a disservice to public health and environmental protection in North Carolina,” Reeder and Williams wrote. “It doesn’t help that political special interest groups perpetuate his exaggerations and fuel alarm among citizens for their own purposes.”

The statement was the last straw for Davies, who issued a letter resigning from the Division of Public Health (DPH) on Wednesday night. Davies defended Rudo and claimed her superiors in DPH and the Department of Health and Human Services (DHHS) were fully involved in all decisions.

“The [statement] signed by Randall Williams and Tom Reeder presents a false narrative of a lone scientist … acting independently to set health screening levels and make water use recommendations to well owners,” she wrote. “In fact, and as I briefed you in August 2015, NCDHHS followed a process that engaged DPH and DHHS leadership in all decisions.

“Upon reading the open editorial yesterday evening, I can only conclude that the department’s leadership is fully aware that this document misinforms the public,” she wrote. “I cannot work for a department and an administration that deliberately [mislead] the public.”

McCrory addressed the dispute again while at a ribbon cutting ceremony on Thursday.

“We basically have a disagreement among scientists,” McCrory said, according to WRAL. “One group of scientists, which I support, believe the public ought to get all the information about the water, not limited information and one opinion.”

State Democrats, in their continued feud with McCrory and his administration, are calling for an investigation. “There is at least an appearance of pay-to-play politics, and, unlike other incidents of McCrory rewarding his friends and donors with political favors, this insider dealing puts lives at risk,” North Carolina Democratic Party spokesman Dave Miranda told reporters.

It is unclear who would lead such an investigation. The state attorney general, Roy Cooper, is running against McCrory for governor in November.

August 15, 2016

MISO Reliability Subcommittee Briefs

MISO wants to know how it can improve frequency response under an evolving generation fleet and is asking for stakeholder involvement to draft an issues statement.

“This isn’t a new topic. The industry has been grappling with the issue for years,” said Durgesh Manjure, MISO’s manager of resource adequacy coordination.

Manjure said MISO hasn’t encountered the frequency response challenges that other systems such as ERCOT have encountered.

“But that doesn’t mean everything is fine and we won’t have to introduce something to keep this reliable trajectory going forward,” Manjure said during an Aug. 10 meeting of the Reliability Subcommittee (RSC). “By no means is this an issue now or next year, but I can’t say that with the same level of confidence for five years out.”

The RTO said that “opportunities exist to improve dynamic models” and performance measurement.

MISO said its changing fleet is driving the frequency response discussion, with coal taking an ever-shrinking share, while gas and wind sources climb. Manjure said MISO relies on coal for “most if not all” of its frequency response, but technological advancements are allowing other generation types to provide a governor-like response to a drop in frequency.

Between 2009 and 2015, MISO’s coal generation capacity dropped from 71.8 GW to 65.2 GW, while wind capacity almost doubled from 7.6 GW to 15 GW. Natural gas, responsible for only 6% of MISO energy production in 2010, now claims 28%; coal’s share fell from 73% to 45% over the same period.

According to NERC’s State of Reliability 2016 report, frequency response reliability in the Eastern Interconnection is expected to decline from the approximate 2,500 MW/0.1 Hz in 2012 to a little more than 2,000 MW/0.1 Hz in 2019.

Manjure said MISO wants to know if its models accurately reflect actual systemwide performance and what fuel mix point would render MISO’s frequency response inadequate. MISO is also asking if it needs to improve its tools that measure frequency response and revise Tariff or market mechanisms relating to frequency response.

“This is very high-level, very open to feedback,” Manjure said.

Manjure asked for stakeholder input that will be used to shape an issues statement in the coming weeks.

Improvement to Pseudo-Ties Process on MISO Horizon

Kyle Abell of MISO’s market planning division said MISO is trying to improve the congestion management process for its increased volume of pseudo-ties.

MISO said it has experienced escalating pseudo-tied generation with load farther from the seams in 2016. In the 2015/16 planning year, MISO-based generation pseudo-tied into PJM equaled only 155 MW; in the 2016/17 planning year, the amount is expected to reach about 2,000 MW. In the 2017/18 planning year, pseudo-ties are expected to creep toward 2,800 MW, with many of the deeper pseudo-ties sent to attaining balancing authorities with “very limited or no modeling-based visibility” of how their usage affects the larger MISO system.

Abell said MISO is contemplating new requirements for approving a pseudo-tie, including notification, pre-assessment and conditional approval steps. In addition, the RTO may set out requirements for an attaining balancing authority’s network model for proposed pseudo-ties. Currently, MISO reviews and approves pseudo-tie requests, while balancing authorities are responsible for market-to-market redispatch.

MISO asked stakeholders for suggestions to improve its pseudo-tie congestion management before Aug. 26. The RTO also said it would meet with neighboring balancing authorities and RTOs and its Independent Market Monitor to discuss the issue. Abell said he would make another pseudo-tie presentation at the Aug. 16 Planning Subcommittee meeting.

MISO plans to revise its processes around congestion caused by pseudo-ties through November, in time to draft a work plan to implement the changes in December.

Smooth Operations in MISO Despite ‘All-Time Hottest’ July

MISO operations performed well in July despite several hot weather and severe weather alerts, said Steve Swan, MISO senior manager of dispatch and balance.

Swan said July 2016 was the “all-time hottest July” for multiple cities in the southern portion of the MISO footprint. It was also the driest month since MISO’s creation for some southern MISO locations. Load peaked at 120.6 GW on July 21.

MISO reported that July 10, 12 and 20 fell outside of its unit commitment performance targets since forecasted load didn’t materialize due to thunderstorm activity; units that were preemptively called up had to stay online to fulfill their minimum run times. MISO also had one maximum generation event in July.

July also marked the first month MISO was required to abide by NERC’s balancing authority area control error limit (BAL-001-2) standards, which limit interconnection frequency errors to less than 30 minutes. Swan said MISO did not experience an error lasting longer than 15 minutes event in July.

RSC Chair Tony Jankowski commended MISO for its operations in the face of the hot weather. “We’ve had a pretty good summer so far, and MISO’s gotten us through some hot weather we haven’t seen in a while,” Jankowski said.

Winter is Coming and Coordinated Seasonal Assessment is Scoped

With Labor Day looming, MISO is already thinking about winter. Its 2016/17 winter Coordinated Seasonal Assessment, which assesses risks and system capabilities will include four main analyses, said MISO’s Katie Hulet:

A steady-state AC analysis to study the effect of simple and complex contingencies;
An analysis identifying large phase angle differences associated with reclosing a transmission line;
A voltage stability analysis that will assess four critical interfaces for high transfers in combination with transmission and generator outages, which can cause stability issues; and
A first contingent incremental transfer capability analysis to study the impact of high megawatt transfers and flowgate limitations. This analysis will examine six transfers in addition to wind transfer sensitivity.

MISO also will use only approved retirements and planned and forced transmission and generation outages lasting two months or more between December and February in its assessment.

Hulet said MISO would return to the RSC in November to provide the study’s results.

— Amanda Durish Cook

August 15, 2016

MISO to Begin Charging Tx Fees on PJM Exports

By Amanda Durish Cook

MISO last week filed revised Tariff language allowing it to recover costs for multi-value transmission projects that benefit PJM customers by charging a fee on exports to PJM (ER10-1791-003). The Aug. 12 compliance filing requested the new language be retroactive to July 13, 2016.

Last month, FERC partially lifted the three-year-old restriction on MVP allocations for exports in response to a 2013 remand from the 7th U.S. Circuit Court of Appeals. (See FERC Looks Again at Export Pricing for MISO MVPs.)

MISO Transmission Fees PJM — Foundations are laid for Ameren’s Illinois Rivers transmission project, a 345 kV line stretching from West Adair, Mo., to Sugar Creek, Ind. The line consists of five multi-value projects, and portions are expected to come online as early as this year.

The commission said it was persuaded by the large-scale wind buildout “capable of serving both MISO’s and its neighbors’ energy policy requirements.”

It also cited “the reported need of PJM entities to access those resources; and the reported need for MISO to build new transmission facilities to deliver the output of those resources within MISO for export.”

“Given these changes, it is appropriate to allow MISO to assess the MVP usage charge for transmission service used to export to PJM just as MISO assesses the MVP usage charge for transmission service used to export energy to other regions,” FERC concluded.

MISO created the MVP category six years ago for projects that address more than one reliability or economic need across multiple transmission zones. The RTO originally intended to allocate project costs to all of its load and exports, but FERC excluded the export charge because of concerns over rate pancaking.

Chris Miller, FERC’s liaison to MISO, said the RTO removed Tariff language that had prohibited it from charging exports. Affected portions include Attachment MM, Schedule 26-A, Schedule 39 and Attachment L.

MISO also made an informational filing in early August detailing multi-value, market efficiency and baseline reliability projects approved during the Transmission Expansion Plans in 2014 and 2015 (ER13-186, ER13-187). While 140 baseline reliability projects were approved in the two years, only one market efficiency project was greenlit.

The RTO did not approve any MVPs in 2014 or 2015. It said its $6 billion 2011 MVP portfolio — 17 projects in various transmissions zones over nine states — left only local reliability projects to be addressed for the time being.

Three of the projects are in service, with the remainder scheduled to be operational in three to five years.

August 15, 2016

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM is considering providing generation operators an indicator to signal that the RTO has entered emergency conditions, which triggers a performance assessment hour under Capacity Performance rules.

The RTO will determine if there should be any delay in the notification process and, if so, for how long, PJM’s Rebecca Stadelmeyer said. Stakeholders requested that PJM also ensure the signals don’t create any type of market advantage.

Stadelmeyer also clarified that non-ramp-limited basepoints have no impact on calculating either performance bonuses or nonperformance charges during a PAH.

The question arose because generators had been asking for the basepoints to be sent via PJM’s network, thinking they could help estimate units’ expected performance, Stadelmeyer said.

Non-ramp-limited basepoints are theoretical expectations based entirely on the economics of the current LMP and regardless of the unit’s actual capabilities. Ramp-limited basepoints, however, are developed from information about each unit submitted by operators into PJM’s systems.

Nonperformance charges are imposed when a unit’s output fails to meet its expected performance, and bonuses occur when actual output exceeds expected performance without exceeding PJM’s dispatch instructions. Expected performance is calculated by multiplying a balancing factor by the amount of a unit’s unforced capacity (UCAP) that clears as CP in a Base Residual Auction.

Balancing factors are hard to estimate, Stadelmeyer said, so she urged using the maximum 1.0 to identify the highest possible expectations.

PJM also clarified that the difference between UCAP and installed capacity (ICAP) is also available for bonuses as long as the RTO has dispatched the unit to that level.

In May, FERC rejected Tariff changes that would have exempted a capacity resource from nonperformance charges if it was following the RTO’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. The changes were designed as an interim solution to guard against generators self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges. (See FERC Rejects Ramp Rate Exception in PJM Capacity Rules.)

Post-Polar Vortex Tools Enable PJM to Better Face Severe Weather

Thanks in part to new forecasting, scheduling and reserve-checking tools implemented after the polar vortex of 2014, PJM was better able to weather a seven-day July heatwave, PJM’s Chris Pilong told the Operating Committee last week.

The RTO recorded its 13th-highest peak load at 151,822 MW on July 25, a day that saw an average LMP of $35.51. During the hot spell, which ran July 21-27, the daily average LMP ranged from $25.88 on July 26, which recorded a peak load of 143,654 MW, to $42.72 on July 27, which saw a peak load of 146,166 MW.

Pilong said the experience was good news for PJM, which wanted to gauge the self-scheduling behavior of generators now that Capacity Performance is in effect. The RTO doesn’t want generators to disregard its dispatch orders and self-schedule more capacity to avoid penalties when they believe they are approaching a performance assessment hour. (See “Ramp Rate Approach Would Excuse Nonperformance Penalties,” PJM Markets & Reliability and Members Committees Briefs.)

“The day-ahead self-scheduled megawatts didn’t change much from the past few summers,” he said. “We’re not seeing a big shift.”

Day-ahead self-schedules for July 25 stood at 69,476 MW, compared with 68,649 MW a year ago, when load hit 143,633 MW. In real time, generators self-scheduled 73,177 MW, compared with 76,430 MW a year ago.

Self-scheduled units are price takers and cannot set marginal prices; they also are ineligible for operating reserve credits.

July 25 was the first time under the new market construct that PJM issued a maintenance outage recall. It canceled 11 planned outages, totaling 124 MW over 72 hours. Eight of them, a sum of 48 MW, were online by noon July 25; the remaining three, totaling 76 MW, did not return and were converted to forced outages.

An RTO-wide hot-weather alert was issued July 22-25. A heat advisory was issued July 21 in the ComEd zone and July 26-28 in Mid Atlantic and Dominion.

The grid experienced no transfer or interconnection reliability operating limits (IROL) issues during the hot weather, Pilong said.

However, two 765/345-kV transformers tripped in different parts of the system, causing local congestion. (See “Grid Remains Strong During Recent Heat Wave,” PJM Markets and Reliability and Members Committees Briefs.)

PJM’s new tools address two scheduling concerns leading into the polar vortex. Operators’ ability to view the capacity position for the next several days was limited, as was their capacity to capture generator reserves in real time in order to validate their calculations.

In June 2014, PJM rolled out its “long lead” tool, which consolidates load forecasts, safety margins and generator data, and adopted a new procedure for scheduling generation that includes a seven-day look-ahead.

Last September the RTO developed an instantaneous reserve check, allowing it to validate unit reserves in real time.

Pilong said the new tools helped reduce balancing operating reserve (BOR) payments. BOR payments totaled $18.1 million from June through August 2015. That amount stood at $10.1 million through July 26, 2016.

Uplift payments for July 25 came to nearly $1.1 million, compared with $447,118 for the hottest day in 2015, which occurred on July 28.

Metering Task Force Presents Proposal to Improve Clarity

PJM presented the first read of an 11-point proposal for manual and Tariff changes to close the gap between PJM’s metering requirements and members’ understanding of the rules.

The proposal was outlined by Nancy Huang of the Metering Task Force, which was formed by a problem statement approved Sept. 8. (See “Metering Requirements to Receive Overhaul,” PJM Operating Committee Briefs.)

The group also recommended two topics for further study: minimum metering requirements for location and density to ensure system observability, and metering requirements for distributed generation.

The revisions aim to reduce the risk of non-compliance, provide clarity around the specifications and design of new equipment, improve the energy management system’s state estimation solution and maintain operation reliability and market fairness.

The proposal is set to go before the Members Committee on Sept. 29, with a FERC filing expected in October.

Systems Information Committee Heads into the Sunset

Members approved sunsetting the Systems Information Committee.

Topics related to the energy management system will be assigned to the Data Management Subcommittee (DMS), which will meet next on Aug. 25. Remaining topics will be transitioned to the new Tech Change Forum, which will hold its first meetings Sept. 27-28.

To accommodate the changes, the Operating Committee also approved modifying the DMS charter.

The DMS will now function as a joint subcommittee, with generator and transmission owners addressing pertinent issues and TOs considering topics applying only to them.

— Suzanne Herel

August 15, 2016

Company Briefs

Energy Future Holdings last week filed a third amended joint reorganization plan and related disclosure statement with the U.S. Bankruptcy Court in Delaware.

EFH is set to begin its latest attempt to exit bankruptcy this month after the deal at the center of a prior plan fell apart after it had been confirmed by Bankruptcy Court Judge Christopher S. Sontchi.

Energy Future, the largest power company in Texas, filed for Chapter 11 in April 2014 after it failed to meet its debt obligations as electricity prices weakened. The bankruptcy is one of the largest ever in the United States.

More: Bankrupt Company News

Troubled Kemper Needs Another Month, $43 Million

The controversial, multi-billion-dollar Kemper Power Plant, which began making synthetic gas from coal July 14, will take an additional month to finish and cost an extra $43 million, Mississippi Power Co. announced last week.

The oft-delayed coal gasification plant, whose costs have increased to $6.8 billion, is now planned for a Halloween completion. The most recent cost overruns prompted Mississippi Power Co. to write off $81 million in losses in its second quarter.

Mississippi Power parent Southern Company said it needs the additional month to achieve “sustainable operations” by adjusting the two gasifiers that transform soft lignite coal into synthetic gas and to complete testing on the technology that removes carbon dioxide from the gas.

More: Jackson Free Press

Black Hills Energy Starts $54 Million Tx Project

Black Hills Energy started construction on a $54 million, 147-mile transmission line running from eastern Wyoming to western South Dakota. Planning for the project took 10 years, and construction crews started cleaning land on the route last week.

Most of the land is owned by the state or federal governments, but agreements were reached with 24 property owners to allow access to their land. A company spokesman said it would be completed by mid-2017.

More: Rapid City Journal

Chesapeake Gives Up Barnett Assets to Private Group

Chesapeake Energy Corp. said it has agreed to hand over its Barnett Shale holdings to a private-equity-backed operator. The move allows Chesapeake to avoid almost $2 billion in pipeline contracts.

Chesapeake issued a statement saying it will give its interests in the North Texas Barnett region, estimated to be worth as much as $1 billion, to First Reserve Corp.-backed Saddle Operating LLC. The move will cut Chesapeake’s shipping and processing costs by $715 million between now and the end of 2017 and will eliminate $1.9 billion in long-term pipeline agreements.

The Barnett Shale, once at the forefront of the U.S. shale boom, lost its competitive advantage when gas prices collapsed and it was eclipsed by lower-cost production areas closer to Eastern markets. The Barnett is Chesapeake’s second-smallest production region, accounting for 10% of the company’s output.

More: Bloomberg

Duke Issuing $3.75 Billion in Debt to Finance Piedmont

Duke Energy will issue three series of unsecured bonds, totaling $3.75 billion, to help finance its $4.9 billion purchase of Piedmont Natural Gas. The first series, with an interest rate of 1.8%, will be due in 2021; the second series, at 2.65%, will be due in 10 years. A third series, carrying the highest interest rate of 3.75%, will be due in 30 years.

The company said it expects the purchase to close by the end of this year, but it could come as soon as the North Carolina Utilities Commission approves the merger. Hearings on the purchase concluded last month, and briefs are due at the end of this month.

More: Charlotte Business Journal

SolarCity Panel Plant Start Date Moved Up

SolarCity plans to make solar panels in its Buffalo factory by the end of next June, several months earlier than its previous estimate.

Improvements in the equipment the factory will use, and a more efficient plant layout, should allow the factory to make more solar panels than would have been possible under its original design. The plant’s capacity was pegged initially at 1 GW, and company officials would not say how much extra capacity it will add.

SolarCity initially had planned to start making solar panels this year, but slower growth and financial constraints delayed some investment, pushing the production timetable until late 2017.

More: The Buffalo News

Exelon Outlines Growth Strategy, Continues to Push Reforms

At Exelon’s Analyst Day last week in Philadelphia, the company outlined a growth strategy that includes investing in its six electric and gas utilities and adopting innovative technology.

Exelon plans to invest $25 billion in infrastructure and smart grid technology over the next five years.

The company also said it will continue to push policy and market reforms to preserve nuclear plants that face economic challenges.

More: Business Wire

Fire at Four Corners Plant in NM During Decommissioning Work

A chemical fire broke out during the decommissioning of three units at the Four Corners Power Plant in northwestern New Mexico Aug. 11, forcing the plant’s evacuation. The fire was reported at 10:54 a.m. and was extinguished shortly after 1 p.m.

A spokesman for Arizona Public Service Co., which operates the plant, said the fire erupted as crews were working to dismantle a crystalline brine concentrating tower used to purify water for cooling equipment.

APS does not expect the incident to impair its plans to close the units by the end of the year. The remaining two units were offline for maintenance and not affected by the fire.

More: Farmington Daily Times

DTE Plant in St. Clair Burns for 12 Hours

A fire at DTE Energy’s St. Clair County coal-fired power plant burned for 12 hours Thursday night into Friday morning before firefighters were able to extinguish the blaze. There were no injuries at the plant, which is located on the St. Clair River in East China Township.

The fire was reported about 6:30 p.m. Thursday, and all employees were evacuated after shutting down all remaining units. Company and state officials continued to work to determine the cause of the blaze.

The plant is among three slated for retirement by 2023.

More: The Detroit News