Vice President of Finance Jo Biggers has left MISO after 16 years, the RTO announced last week.
MISO CEO John Bear and Biggers in 2015 Source: MISO
MISO said Biggers exited her position “to pursue other opportunities” and that it is beginning a search for a replacement. Biggers was responsible for procurement, facilities, accounting and FERC financial reporting. She joined MISO in August 2000, remaining in the same position throughout her tenure.
Until a replacement is found, MISO has delegated corporate service tasks to Senior Vice President of Compliance Services Steve Kozey. Finance and corporate planning responsibilities will be handled by Vice President of Strategy and Business Development Wayne Schug.
MISO declined to comment further on the departure. Beyond its short announcement, spokesman Jay Hermacinski said the RTO did not “have anything else to add.” Biggers could not be reached for comment.
WESTBOROUGH, Mass. — ISO-NE last week presented the five scenarios it will evaluate in its 2016 Economic Study, which envisions continued reliance on natural gas, renewables, energy efficiency and demand response.
The RTO is in the early stages of Phase I of the two-phase study, which will look at projected needs for 2025 and 2030.
The draft study will analyze the following futures:
The generation fleet meets existing renewable portfolio standards, with natural gas combined cycle units replacing any retiring units and filling any installed capacity requirement shortfalls.
The same as Scenario 1 except that all additional capacity needs, including retirements, are met with new renewable/clean energy resources, including nuclear power.
The “RPS-plus scenario” assumes additional renewable/clean energy resources above existing RPS requirements.
The “no retirement scenario” is the same as Scenario 1, except that RPS requirements are met by renewable/clean energy resources that are interconnected to the system, under construction or approved as of April 1, 2016, with alternative compliance payments — which would support renewable energy projects — used to meet any remaining RPS requirements. Combined cycle plants meet any installed capacity shortfalls.
The same as Scenario 4, except that retired units are replaced with combined cycle plants to meet installed capacity requirements.
Most of the scenarios reflect the region’s commitment to renewable generation and its shift away from coal and oil. “We see little to no generation from oil-fired units,” Michael Henderson, ISO-NE director of regional planning and coordination, told the Planning Advisory Committee on Wednesday.
In Scenarios 1, 4 and 5, fossil-steam resources burn oil, coal and natural gas at existing locations. Scenarios 2 and 3 have very large amounts of zero-dispatch-cost resources such as wind, energy efficiency and solar photovoltaic. And while Scenario 3 adds new import capability, energy imports are about the same as the other scenarios for 2030 because of the large-scale addition of zero-cost resources.
That is especially pertinent following Massachusetts’ approval of legislation requiring the procurement of large amounts of Canadian hydropower and offshore wind. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Phase I will consist of traditional economic study analyses, with an emphasis on production costs.
Phase II will supplement Phase I by discussing several market and operational issues, including Forward Capacity Auction clearing prices, intra-hour ramping, regulation and reserve requirements and access to natural gas.
A draft report is expected to be completed in the fourth quarter.
California must significantly upgrade its transmission system in order to meet its 2030 target of generating 50% of its electricity from renewable resources, according to an interagency study.
“We have either the seventh or eighth largest economy in the world — we need a grid to match that,” state Secretary for Natural Resources John Laird said during an Aug. 15 workshop to discuss the second iteration of the state’s Renewable Energy Transmission Initiative (RETI 2.0). The first initiative focused on helping the state meet a 33% renewable portfolio standard.
But there is uncertainty about the amount of new renewables needed to fulfill the 50% RPS — as well as the most cost-effective transmission solutions required to reach whatever resources are selected.
“It’s very difficult to predict what load will be” in the future, said California Energy Commission Chair Robert Weisenmiller, pointing out that demand for renewables — like other types of generation — will ultimately be driven by economic growth, the penetration of vehicle electrification and the success of the state’s “very aggressive” energy efficiency goals.
State officials conceived RETI 2.0 to determine what combination of renewable resources could meet their environmental goals most cost-effectively and what transmission will be needed to deliver their output. The initiative also seeks to identify the land use and environmental issues that could constrain development and access to resources.
The intended result: an “accelerated, agency-driven, high-level assessment to inform future planning and regulatory proceedings,” according to project director Brian Turner, of the state’s Natural Resources Agency.
Two Policy Developments
Two major policy developments last year drove the development of the initiative.
The first was Gov. Jerry Brown’s executive order directing California agencies to reduce the state’s greenhouse gas emissions to 40% below 1990 levels by 2030. That goal has so far failed to win legislative backing to become codified into law.
The second development was passage of SB 350, which not only increased the state’s RPS to 50% by 2030, but also set higher standards for energy efficiency in buildings, ensured utility progress toward GHG reductions, expressed intent to expand CAISO into other areas of the West and encouraged electrification of the state’s transportation fleet.
Those overlapping objectives are creating challenges for resource planners.
“How do you translate the high-level goals for SB 350 and the executive order into quantifiable objectives?” Turner asked. “How much [renewable resources] might we need to meet the 50% [RPS] by 2030?”
The initiative’s findings indicate that an additional 25 to 108 TWh of renewables will be needed, depending on growth in vehicle electrification, adoption of behind-the-meter solar and the success of energy efficiency programs.
That translates into 7,000 to 31,000 MW of new capacity, assuming a 40% average capacity factor — or 9,000 to 41,000 MW assuming a 30% capacity factor.
Adding to the uncertainty is that a 40% economy-wide GHG reduction could require the equivalent of a 55 to 60% RPS for the state.
Planners working on the initiative found that “environmental and land use constraints tend to favor in-state solar and out-of-state wind” for meeting mandates, but “determining the environmental and transmission access feasibility for in-state wind may [also] be a priority,” according to Turner.
He also said that while low-cost solar is “ubiquitous” in California, a focus on resource and technology diversity would be more cost-effective because of the “long-term integration challenges” posed by an overreliance on solar. Geothermal may offer “important benefits” by 2030, but more investigation is needed into the costs, benefits and transmission access to those resources.
‘Broad Support’
The planners also found “broad support” among industry participants for further assessing procurement of out-of-state resources, with a focus on high-quality, low-cost options that would be complementary to in-state resources. That task is made difficult by a lack of information about the potential for developing the resources themselves and the transmission options for reaching them absent a broader study in cooperation with other Western states, an issue the initiative is seeking to address.
The subject of transmission access fell to the RETI 2.0 Transmission Technical Input Group (TTIG), led by Neil Millar, CAISO’s executive director of infrastructure development.
Fully Deliverable
Millar said that California has sufficient transmission capacity to fulfill the state’s 33% by 2020 RPS, but more will be needed to meet the 50% RPS with “full deliverability” for additional renewable resources. While the TTIG estimates that there is “significant transmission available to accommodate resources beyond 33% on an ‘energy only’ basis” — which would allow for quicker and less costly interconnection — those resources would be subject to curtailment.
Planners evaluated 11 different “Transmission Assessement Focus Areas” to determine the level of upgrades needed to fullfill California’s renewable and GHG goals.
Under California regulations, a generating resource is considered “fully deliverable” if its output can reach its intended load sink without hitting constraints — which typically requires a contracted path from a generator to a utility service area. The state’s rules also allow a utility to count those resources toward its resource adequacy requirement. “Energy-only” resources have no such requirements for deliverability and cannot be counted as capacity.
“The sufficiency of [energy-only resources] from a policy perspective is yet to be determined,” the group found.
To explore potential transmission solutions, the group evaluated seven internal and four transmission assessment focus areas to determine what transmission upgrades would be necessary to make new renewables fully deliverable into each area’s load centers.
For example, the San Joaquin focus area can currently handle 1,823 MW of deliverable and 3,131 MW of energy-only capacity, but developing another 5,000 MW of deliverable capacity to accommodate new resources would require upgrades costing about $440 million. Some areas — like the Tehachapi — would require few upgrades, while other areas require much more to open up renewable development.
Sushant Barave, a lead transmission engineer with CAISO, pointed out that transmission capacity is dynamic.
“Resource additions in one area may impact availability in other areas,” Barave said, adding that mitigating a constraint that limits flows through multiple focus areas would be the most cost-effective approach to planning.
Barave noted that energy-only resources might require less extensive upgrades, prompting CAISO CEO Steve Berberich to ask that a comparison between energy-only and fully deliverable requirements be made explicit in the group’s final report, to be published later this year.
The group also concluded that any out-of-state resources being delivered into California will be injected into one of the focus areas, subjecting new imports to the same transmission constraints as those faced by internal resources.
The potential for renewable imports from other areas of the West is still something of a blind spot for California grid planners. To remedy that, RETI 2.0 created the Western Outreach Project to “gather stakeholder input from across the Western Interconnection regarding the availability of renewable energy and transmission that could contribute to meeting California’s renewable goals,” according to Keegan Moyer, an Energy Strategies consultant working on the project — a collaboration with the Western Interstate Energy Board.
Key Questions
The project is looking to answer a number of key questions, including:
How much additional renewable development is likely in the West?
Where — and in which technologies — is development of renewables likely to occur over the next 15 years?
How will the future mix of renewables affect daily and seasonal power flows in the Western Interconnection?
What load centers could potentially import surpluses from California?
The project also seeks to determine the existing load capacity to deliver power from high-quality renewable areas into California — and what constraints limit additional deliveries.
“How would different expansion options affect deliverability to and from California?” Moyer said.
Another project task is to gain insight into generation fleet trends, including coal plant closures that could free up transmission capacity in the interior West and possible changes to hydroelectric utilization in the Northwest.
The project will also seek to answer the question of how increased use of dynamic scheduling, conditional firm and energy-only resources, and other renewable procurement arrangements will impact transmission availability and needs.
“It’s pretty clear that we have a lot of options,” Weisenmiller said. “We have to do it in a way that minimizes environmental and economic impacts.”
“I think significant progress is being made,” said Michael Picker, president of the California Public Utilities Commission. “The goal here, I think, is to reuse as much as we can, so we don’t have to go new.”
“In the old paradigm we were looking at renewables. Now we’re looking at greenhouse gases,” Weisenmiller said. “We’re in a brave new world that will require a lot of new thinking about how the pieces fit together.”
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.
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.
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.”
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.)
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.
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.
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.”
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.
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.
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.
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 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.
The second quarter wasn’t a great one for most companies in the RTO Insider Top 30, as revenues declined 2% compared with 2015 while profits dropped 15%.
Twelve companies reported increases in revenue, while 15 reported reductions and three were unchanged. The outliers were WEC Energy Group and Avangrid, which saw revenues soar because of acquisitions.
Eleven companies reported an increase in profits while 19 showed declines. FirstEnergy, NRG Energy, Centerpoint Energy and Calpine reported quarterly losses.
It was a really bad quarter for FirstEnergy, which reported a $1.1 billion loss, much of it related to the pending closure of five coal-fired units. The company said it plans to rid itself of its merchant generation and transition to a “fully regulated company.” (See FirstEnergy Posts $1.1B Loss, Eyes Exit from Merchant Generation.)
NRG said most of its second-quarter net loss of $276 million ($0.61/share) — worse than its $9 million loss a year ago — resulted from impairments and losses on asset sales. (See NRG Continues to Pare Down Businesses, Affirms Guidance.)
Centerpoint, which has utilities in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas, reported a net loss of $2 million ($0.01/share), compared with a profit of $77 million ($0.18/share) in 2015. The company said its results were dampened by a $16 million drop in income from Enable Midstream Partners, a gas gathering and processing limited partnership with OGE Energy. The company has offered to sell its 55.4% stake to OGE. (See CenterPoint Abandons REIT Plan; Offers Stake in Gas Partnership to OGE.)
Calpine showed a net loss of $29 million ($0.08/share) versus a profit of $19 million ($0.05/share) a year earlier. The company blamed mark-to-market losses resulting from increases in forward power and natural gas prices. It also said increased hydroelectric generation in the West contributed to lower energy margins for its gas-fired fleet, although this was partially offset by an increase in generation in Texas.
The companies showing the biggest revenue declines in the quarter were Calpine, NRG, NextEra Energy and Public Service Enterprise Group, each of which was down more than 10%.
Company
Market Cap. ($ billions)
Revenue Q2 2016 ($ billions)
% change vs. 2015
Net income Q2 2016 ($ millions)
% change vs. 2015
NextEra
58.47
$3.82
-12.4%
$540
-24.6%
Duke Energy
57.23
$5.48
-2.0%
$509
-6.3%
Dominion Resources
47.89
$2.60
-5.5%
$452
9.4%
American Electric Power
33.13
$3.89
1.6%
$502
16.7%
Exelon
32.37
$6.91
6.1%
$267
-58.2%
PG&E
32.20
$4.17
-1.2%
$210
-48.3%
Berkshire Hathaway Energy
NA
$4.12
-7.4%
$545
-3.9%
Sempra Energy
26.78
$2.18
-7.6%
$17
-94.3%
PPL
24.84
$1.79
0.6%
$483
-163.8%
Edison International
24.82
$2.78
-4.5%
$307
-24.6%
Consolidated Edison
24.11
$2.79
0.0%
$232
5.9%
Public Service Enterprise Group
22.31
$1.91
-17.3%
$187
-45.8%
Xcel Energy
21.75
$2.50
-0.8%
$197
-0.1%
WEC Energy Group
19.75
$1.60
61.6%
$182
124.6%
Eversource Energy
18.19
$1.77
-2.7%
$204
-1.8%
DTE Energy
17.38
$2.26
-0.4%
$152
39.4%
Entergy
14.26
$2.46
-9.2%
$573
284.7%
FirstEnergy
14.19
$3.40
-2.0%
$(1,089)
-682.4%
Avangrid
13.58
$1.44
53.4%
$102
827.3%
Ameren
12.39
$1.43
2.1%
$147
-2.0%
CMS Energy
12.31
$1.37
1.5%
$124
85.1%
Centerpoint Energy
9.66
$1.57
2.6%
$(2)
-102.6%
Alliant Energy
9.02
$0.75
4.2%
$86
23.3%
Pinnacle West Capital
8.68
$0.92
3.4%
$121
-1.3%
NiSource
8.05
$0.89
0.0%
$29
-203.2%
Westar Energy
7.57
$0.62
5.1%
$72
13.5%
OGE Energy
6.21
$0.55
0.0%
$72
-18.3%
Calpine
4.61
$1.16
-19.4%
$(29)
-252.6%
Great Plains Energy
4.38
$0.67
9.8%
$32
-27.9%
NRG Energy
3.93
$2.64
-22.4%
$(276)
2966.7%
TOTAL
$70.44
-2.1%
$4,947
-15.4%
NextEra
NextEra said revenues dropped to $3.82 billion in the quarter, a 12% reduction from a year earlier. Its Florida Power & Light saw a 2.5% drop in retail sales, despite adding 65,000 more customers, due to mild weather.
NextEra Energy Resources, the company’s competitive energy unit, saw operating revenue drop to $970 million from $1.27 billion, due in part to hedging losses and the sale of 3,000 MW of natural gas generation in Texas. It also reported lower revenues from wind assets, which it attributed to lower output and reduced state and federal tax credits.
The company said it expects to add about 2,500 MW of contracted renewable generation in 2016, which would boost its renewable portfolio to 16,000 MW.
Last month, the company, which was rebuffed in its effort to buy Hawaiian Electric, reached an agreement to purchase Dallas-based Oncor in an $18.4 billion deal. (See NextEra Reaches Deal for Oncor.)
PSEG
PSEG reported second-quarter net income of $187 million ($0.37/share), a 46% drop from a year earlier. Operating earnings — which exclude the nuclear decommissioning trust, mark-to-market accounting and material one-time items — were flat year-over-year at $289 million ($0.57/share).
Public Service Electric and Gas’ expanded capital investment program goosed its net income of $179 million ($0.35/share), an increase from the $167 million ($0.33/share) for 2015.
Weather-normalized electric sales for the 12 months ending June 30 were down 0.2% versus a year earlier, despite an increase in the number of customers, because of increased energy efficiency and reduced industrial demand.
PSEG’s wholesale power unit, which earned $166 million ($0.33/share) a year ago, had a net loss of $11 million ($0.02/share) as output dropped 6% because of mild weather, low gas prices and a decline in PJM capacity revenues.
PSEG Power also took a hit from an extended refueling outage at the Salem 1 nuclear unit for repairs. The outage dropped the average capacity factor for the company’s nuclear fleet to 83% for the quarter, down from 86% a year earlier.
PSEG’s Peach Bottom nuclear plant, however, increased its output following modifications that increased its capacity by 130 MW.
Output from its combined cycle fleet declined to 4.4 TWh from 4.6 TWh due to mild weather, while low gas prices reduced the dispatch of its coal-fired units, which saw production drop to 0.9 TWh from 1.3 TWh.
CEO Ralph Izzo said the company was maintaining its operating earnings guidance for the year 2016 ($2.80 to $3/share). “However, reaching the upper end of guidance will be difficult even with improvements seen in the power markets, expectations for warm summer weather, normal operations and management of O&M for the remainder of the year,” he said.
Entergy
Entergy had a big earnings surprise, reporting second-quarter net income of $572.6 million ($3.11/share), almost tripling analysts’ expectations of $1.05/share, as polled by Thomson Reuters.
“We continue to make progress toward meeting our objective of steady, predictable growth at the utility while reducing our [Entergy Wholesale Commodities] footprint,” Entergy CEO Leo Denault said.
One step to shrinking that footprint came earlier this month, when the company agreed to sell its FitzPatrick nuclear plant in New York to Exelon for $110 million. The plant, which Entergy had planned to close, had a net book value $143 million. (See Entergy Sells FitzPatrick to Exelon.)
Net revenue was boosted by the company’s acquisition of the 1,980-MW Union Power combined cycle plant in Arkansas, Entergy Arkansas’ rate increase and higher industrial sales. The company cited strong demand from petroleum refiners who “continued to operate at high capacity levels compared to last year.”
Looking forward, the company also noted that it awarded itself contracts to build generation following competitive solicitations for Entergy Louisiana and Entergy Texas.
Methodology
The RTO Insider Top 30 includes the largest companies (by market capitalization) with significant presence in the seven RTOs and ISOs in the U.S. Since initiating the Top 30 in the first quarter, we have added Great Plains Energy and eliminated National Grid, a U.K.-based company that does not report its results quarterly. Expect more shuffling if Great Plains wins regulatory approval for its proposed acquisition of #26 Westar Energy.
Twelve companies reported increases in revenue, while 15 reported reductions and three were unchanged. The outliers were 