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

RTO Insider Top 30: Revenues, Earnings Down in Q2

By Rich Heidorn Jr.

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.

August 15, 2016

Monitor: PJM Markets Competitive, but Have Room for Improvement

By Suzanne Herel

PJM’s wholesale energy, capacity and regulation markets were competitive for the first half of the year, but there is room for improvement, according to the second quarter State of the Market Report by Monitoring Analytics. The Independent Market Monitor made new recommendations for the energy, capacity and ancillary services markets.

During periods of high demand, the market’s performance “raised a number of concerns related to capacity market incentives, participant offer behavior in the energy market under tight market conditions, natural gas availability and pricing, demand response and interchange transactions,” the report said.

The report also called efforts to subsidize uneconomic units a “threat” to PJM market design.

The report includes five new recommendations and one modified recommendation. Two are classified as high priority; the others are ranked medium.

One of the high priority items concerns the capacity market. The Independent Market Monitor said that the costs incurred by pseudo-tied units should be borne by the unit and included in its offers into the market.

The other, first reported in 2012, calls for the emergency load response program to be treated as an economic resource that does not only respond after an emergency has been called.

The medium recommendations were:

Energy market: Clearly state the policy on the use of constraint relaxation and price-setting logic.
Capacity market: Re-evaluate mitigation rules for offers by demand resource and energy efficiency resources.
Capacity market: Eliminate the energy efficiency add-back mechanism so market clearing prices are not impacted.
Ancillary services: Eliminate separate payments for reactive capability and have generators recover its cost in the capacity market.

Prices, Demand Down

Lower fuel prices and less demand caused energy market prices to drop significantly over the first half of last year, the report said.

The load-weighted average real-time LMP was $27.09/MWh, a 36% drop from $42.30/MWh in 2015.

Average real-time load dropped 5.3% year over year, from 90,586 MW to 85,800 MW.

Net revenue, a measure of market performance and of the incentive to invest in new generation, decreased in the first six months of the year relative to 2015. Total net revenues, including both capacity and energy, dropped for a new combustion turbine (-50%), combined cycle (-41%), coal plant (-75%), diesel (-81%), nuclear plant (-46%), wind installation (-31%) and solar installation (-44%).

Combustion turbines (CTs) and combined cycle units (CCs) that entered the PJM markets in 2007 in three representative locations did not cover their total costs, including the return on and of capital. CTs and CCs that entered the PJM markets in 2012 did cover their total costs in the eastern PSEG and BGE zones but did not cover their costs in the western ComEd zone.

Mild winter weather, paired with low fuel prices and LMPs, enabled PJM to reduce uplift charges from $240.3 million to $63.9 million, a 73% cut.

Congestion costs dropped from $918.6 million to $479.1 million, a 48% reduction.

The report also said that auction revenue rights were not an effective way to return revenue to load. Together with financial transmission rights, they offset 86.5% of total congestion costs for the 2015 to 2016 planning period.

August 15, 2016

CAISO Refines Cost Allocation Proposal for Expanded BA

By Robert Mullin

CAISO met with stakeholders last week to refine a proposal for allocating costs of new transmission facilities in an expanded balancing authority (BA) that would include areas of the West outside California.

CAISO Plus Pacificorp Map (CAISO) - CAISO Refines Cost Allocation Proposal for Expanded Balancing Authority — The current CAISO footprint and PacifiCorp’s balancing areas would represent separate sub-regions under the ISO’s TAC proposal.

ISO staff laid out options for creating “default” cost allocation provisions, a requirement under FERC Order 1000, at an Aug. 11 working group.

Under CAISO’s proposal, “new facilities” would include new construction, additions and upgrades approved through the transmission planning process for an expanded ISO.

It would apply the transmission access charge (TAC) only to ISO-wide — or “regional” — projects meeting at least one of three criteria:

Receives a rating of 200 kV or more;
Facilitates a connection between two sub-regions; or
Creates, supports or helps increase intertie capacity with a neighboring balancing authority area.

The proposal also creates a new category of “sub-regional” transmission projects excluded from the ISO-wide TAC, including facilities under 200 kV, as well as those constructed or approved before expansion. Costs for those projects would be allocated entirely to the sub-region requiring the project — such as PacifiCorp’s service territory or the current CAISO BA.

Planning Process

CAISO staff told stakeholders that the TAC proposal is predicated on the assumption that the ISO’s current planning process is “a reasonable model” for expansion.

“We redesigned our [planning process] in 2010 and we think it’s a good model,” said Lorenzo Kristov, CAISO principal of market infrastructure and policy. “There’s no reason to think it wouldn’t work with expansion.”

That detail is important because the decision-making approach under the current planning process underpins the framework for the ISO’s proposed default cost allocation scheme.

CAISO breaks down projects into three categories: reliability-driven, policy-driven and economically driven.

ISO transmission planners run a proposed project through three stages of analysis, first determining the project’s reliability benefits, followed by an assessment of how the project helps fulfill state objectives for increased renewable generation. A third stage examines the economic benefits of the project.

Some projects may have more than one driver.

“We want to avoid tagging projects as just being economic or policy — the world doesn’t work that way,” said Neil Millar, the ISO’s executive director of infrastructure development.

Economically driven projects must produce total benefits exceeding the project’s cost — demonstrating a benefit-cost ratio of 1.0 or greater. To calculate those benefits, the ISO relies on the transmission economic assessment model, which considers savings from more efficient dispatch, reduced line losses and congestion and increased resource adequacy.

While the ISO said it weighs economics in its evaluation of any proposed project, reliability- and policy-driven projects don’t have to meet the same threshold as economically driven projects.

“We look at it this way so that people don’t think we can kill a project just for economic reasons, because it might meet a reliability and policy need,” Millar said.

The analytical approach underlying the planning process would inform the ISO’s proposed default cost allocation scheme under a redesigned TAC.

Benefit-Cost Ratio

Under the TAC proposal, costs for a project — including those for a reliability- or policy-driven project — with a benefit-cost ratio of 1.0 or greater would be allocated to sub-regions in proportion to the total economic benefits assessed for each sub-region.

For projects with a ratio less than 1.0, a portion of the cost would be allocated across sub-regions according to financial benefits, under the assumption that even uneconomic projects provide some economic benefits for market participants. Leftover charges — representing the portion of the costs not covered by economic benefits — would be assigned to the sub-region responsible for the reliability need or policy mandate driving the project.

In cases where multiple sub-regions derive policy or reliability benefits, leftover costs would be allocated in proportion to the total internal load for those areas during the year in which the project is placed into service, according to the proposal.

“The economics would be used to allocate the first tranche of needs, and then the incremental policy or reliability needs would be allocated on an incremental basis,” Millar said.

The ISO is also considering a concept by which the avoided costs for a reliability- or policy-driven alternative would be factored into a sub-region’s total benefits calculation for a proposed project.

A potential downside: A sub-region’s TAC allocation could rise based on the assumed cost of a “hypothetical” project.

“Is the avoided cost of a hypothetical sub-regional alternative an appropriate basis for cost allocation?” the ISO asked stakeholders.

Feedback

“This looks good [as] a conceptual idea,” said David Oliver, a managing consultant with Navigant. “But we’re talking about transferring money in sub-regions and that’s often not a fun thing to do.”

LS Power Vice President Sandeep Arora said, “I think this is very encouraging — the entire approach of looking at a transmission project not just fitting into one bucket but looking at the various benefits a project brings.”

The ISO said updating the TAC plan is a “central policy element” in the development of a Western RTO. Utility commissions in five states must grant approval before Portland-based PacifiCorp can join the ISO. The cost allocation scheme is likely to weigh heavily in regulators’ decisions.

CAISO planners initially expected to wrap up the TAC proposal in time to present it to the ISO’s board of governors in late August, in concert with a push to submit an RTO governance plan to California lawmakers before the end of this summer’s legislative session. (See CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area.)

The ISO got more breathing room after Gov. Jerry Brown’s Aug. 8 decision to postpone efforts to win legislative approval to expand the ISO until early 2017. (See Governor Delays CAISO Regionalization Effort.)

“Last time we had a meeting on this topic … we were still contemplating taking this to the board at the end of August, as ridiculous as that sounds,” CAISO’s Kristov said.

Instead, the ISO is likely to continue work on the proposal for the rest of the year, Kristov said.

August 15, 2016

State Briefs

Report Advocates a More Aggressive RGGI

A new Acadia Center report suggests the Regional Greenhouse Gas Initiative (RGGI) should adopt more aggressive emissions targets aligning it more closely with those of some member states. The climate-change advocacy organization also recommends extending the RGGI caps to 2031 to coincide with the proposed federal Clean Power Plan.

“RGGI continues to prove itself as an effective means of reducing carbon emissions and supporting economic growth,” said Daniel L. Sosland, Acadia Center president. “Now, Northeast and Mid-Atlantic states have an opportunity to build on RGGI’s success and lead the country by taking the steps necessary to meet state and federal climate requirements.”

RGGI states have committed to reducing emissions by about 40% across their economies by 2030. In addition, eight of the nine participating states have established 2050 requirements for 80% reductions.

More: Acadia Center

Del. Officials Say W.Va. Plant is Polluting Their Air

Delaware officials are asking federal regulators to take action against a coal-fired West Virginia plant they say is contributing to pollution in the First State.

The Department of Natural Resources and Environmental Control says emissions from the Harrison Power Station near Haywood exceed federal standards. The plant is 245 miles west of the Delaware border.

The move is the latest effort by state officials to battle emissions produced in Maryland, Pennsylvania and other states that they say are making it impossible for Delaware to meet EPA air quality standards.

More: Delaware Online

CALIFORNIA

Watchdog Says Energy Companies Influenced California Democrats

A public interest group said Gov. Jerry Brown and California Democrats have received more than $9.8 million in campaign contributions from energy companies during the past eight years.

In a report titled “Brown’s Dirty Hands,” Consumer Watchdog alleges that the donations coincided with the companies’ winning political favors — including a deal between Southern California Edison and the state’s Public Utilities Commission that allowed the utility to charge ratepayers with most of the cost of shutting down the San Onofre nuclear generating station.

“The report really paints a troubling picture,” said Jamie Court, the group’s president. A spokesman for the governor called the report “cuckoo.”

More: Pasadena Star-News

Pilot Program to Generate Power from California Highways

The California Energy Commission is initiating a series of pilot programs next year that will attempt to generate electricity from sensors in the roadway triggered by cars driving along the state’s freeways.

The project will rely on piezoelectric technology, which involves installing tiny sensors beneath the road surface to capture energy produced by vibrations of passing cars. Gov. Jerry Brown vetoed a bill, introduced by Assemblyman Mike Gatto, to fund the project, but the commission expressed interest in the technology shortly after.

“As an engineer, I could just see that vision of all these people driving down the roads and all that energy that’s sitting there and goes nowhere,” said Michael Gravely, a commission deputy division chief.

More: KCRA

DISTRICT OF COLUMBIA

OPC Takes Exelon Merger to Appeals Court

The Office of the People’s Counsel (OPC) is asking the D.C. Court of Appeals to examine the Public Service Commission’s order approving the Pepco/Exelon merger. (See Exelon Closes Pepco Merger Following OK from DC PSC.)

“Judicial review is critical not only because the decision impacts this case but all cases going forward in terms of the process and procedures the commission uses in making its decisions,” said Sandra Mattavous-Frye of the OPC. “It concerns the amount of process, or lack thereof, afforded to all parties, and the manner in which settlements are decided.”

Mattavous-Frye said the OPC also is opposing Pepco’s $85 million rate increase request.

More: Office of People’s Counsel

ILLINOIS

Lawmakers Urged to Follow NY’s Lead

A group of pro-nuclear Illinois mayors and community leaders have urged Illinois lawmakers to follow the lead of New York State policymakers, who arranged a nuclear bailout, expediting Exelon’s decision to buy and operate Entergy’s James A. FitzPatrick nuclear station.

In a letter sent to Gov. Bruce Rauner and lawmakers, the local leaders praised New York’s Clean Energy Standard, which includes subsidies for nuclear stations. “New York’s Clean Energy Standard is a road map for effective policy in Illinois,” said Tim Followell, city administrator of Clinton, Ill., which is home to one of the two nuclear stations Exelon says it will be closing because it is losing money due to low wholesale prices.

Followell and others have been pushing for passage of an Illinois version of a bill that would provide credits for nuclear stations. Critics have tagged that proposal, called the Next Generation Plan, a bailout.

More: Quad-City Times

AG Settles Case with Ethical Electric

Attorney General Lisa Madigan has reached a settlement with competitive retail energy supplier Ethical Electric requiring the company to refund up to $3 million for misleading customers.

Ethical Electric touted its power as being generated exclusively by renewable energy sources, when, in fact, it was sourced from a variety of generators paired with renewable energy certificates.

It also falsely promoted its fees as comparable with Commonwealth Edison’s rates, when they were more expensive.

More: Energy Manager Today

IOWA

Landowners File Yet Another Motion Against Dakota Access

A group of 14 landowners has filed a motion in Polk County District Court seeking to halt construction of the $3.8 billion Dakota Access Pipeline, asking the court to review the Iowa Utilities Board (IUB) ruling that the pipeline could use eminent domain.

“The landowners believe that Dakota Access is not a public utility and should not have the ability to use eminent domain to forcibly access Iowa landowners’ property to build a private pipeline,” Bill Hanigan, an attorney for the property owners, argued in a motion. He said the IUB misinterpreted Iowa law in calling the pipeline a public utility.

The 1,168-mile pipeline, parts of which are already under construction, will carry Bakken crude oil from North Dakota to terminals in Illinois.

More: The Gazette

KANSAS

Regulators Outline Standards for Upcoming Acquisition Dockets

The Corporation Commission said last week its members will consider whether Great Plains Energy’s proposed acquisition of Westar Energy will “promote the public interest” when it votes on the deal next year. Commissioners adopted merger standards for the Westar/Great Plains union and two other unrelated mergers to ensure the KCC takes a “consistent approach.”

The criteria the commission will consider include the merger’s effects on consumers, the environment and state and local economies and to the utilities’ communities.

The KCC is expected to hear the Westar Energy and Great Plains acquisition docket sometime between Jan. 3 and March 30. The two other acquisitions in front of the KCC are the purchase of Empire District Electric Co., of Joplin, Mo., by Liberty Utilities (Central) Co., a subsidiary of Algonquin Power & Utilities Corp., and a proposal for ITC Holdings to become an indirect, majority-owned subsidiary of FortisUS with minority ownership by GIC Ventures.

More: The Topeka Capital-Journal (Kan.)

KENTUCKY

LG&E Awarded Customer Charge for Clean Up

The Kentucky Public Service Commission has approved a request by Louisville Gas & Electric Co. (LG&E) to assess a new monthly charge for customers to pay for the cleanup of coal ash ponds. The commission approved the charge of 30 cents a month for this year for the typical residential customer, which will increase to $2.08 a month in 2024.

The commission approved a similar charge for LG&E’s sister company, Kentucky Utilities (KU), which was set at 30 cents per month and will later increase to $3.12 a month. The charges were approved after the two companies requested $994 million to meet new federal coal-ash cleanup rules. LG&E said it will spend more than $300 million in cleanup efforts. KU said it will spend about $675 million.

More: Louisville Courier-Journal

MICHIGAN

State Preps for Higher Rates In Face of Supply Shortage

Some consumers in the state are expecting electricity price increases in the coming years because of DTE Energy’s decision earlier this year to shut down seven coal-fired plants.

The Public Service Commission’s five-year outlook anticipates electric supply shortfalls through summers 2017 and 2020. The Lower Peninsula is expected to see a 270-MW shortage next year, an improvement over the 520-MW shortage that the PSC previously predicted. MISO’s Midwest region is predicted to fall short of the reserve margin requirement by 2018.

Tim Arends, executive director of Traverse City Light & Power, said the municipal utility’s annual power prices nearly doubled to $850,000 this year. The utility recovers the cost through a user fee.

More: Traverse City Record-Eagle

Consumers Installing More Safety Buoys Near Hydroelectric Dams

Consumers Energy in installing more safety buoys across rivers below its Michigan hydroelectric dams to warn swimmers and boaters of the dangers of swirling water released from impoundments.

The utility is working with the Michigan Department of Natural Resources to keep swimmers and boaters out of “potentially unsafe areas immediately downstream of hydroelectric dams.” Consumers will place buoys at 10 dams on five rivers statewide during the year.

Last year, Consumers installed buoys at three dams on two northern Michigan rivers.

More: Post-Bulletin

MISSOURI

PSC Could Quash Westar-KCP&L Merger

The Public Service Commission’s claims of jurisdiction over the $12.2 billion acquisition of a Kansas utility by Great Plains Energy could have significant impact on the deal. Commission staff says job cuts and possible outsourcing spurred by the proposed acquisition could harm existing customers of Great Plains’ subsidiary, Kansas City Power & Light.

The staff claims Great Plains violated a 2001 agreement with the commission, in which it agreed not to acquire any public utilities without commission approval.

Great Plains argues that combining Westar and KCP&L would benefit customers on both sides of the state line. Moreover, it says the commission’s complaint is a moot point because Westar isn’t a public utility under state law, and, therefore, Great Plains doesn’t need the state’s approval to buy Westar.

More: The Wichita Eagle (Kan.)

NEW MEXICO

Regulatory Examiner Recommends 67% Slash to PNM Rate Increase

A state hearing examiner has recommended a 67% reduction to Public Service Company of New Mexico’s (PNM) rate increase request, from $123.5 million a year to $41.3 million a year. The recommendation would result in a 6.4% increase for the average customer, compared to 14.4% under PNM’s request.

The hearing examiner rejected the $152.8 million PNM spent to purchase power from the Palo Verde Nuclear Generating Station in Arizona, which was disputed in a separate commission matter. The examiner also disallowed a $52 million investment in pollution controls at the San Juan Generation Station, which PNM did at the behest of the EPA, but some felt it was unnecessary. The examiner also reduced PNM’s requested rate of return from 10.5% to 9.575%.

PNM can file exceptions to the examiner’s findings, after which the regulatory commission’s general counsel will present a draft order to the Public Regulation Commission (PRC). According to the current schedule, the PRC must make a final ruling in the case by Aug. 31.

More: Albuquerque Journal (N.M.)

NEW YORK

Storage Provider Demand Energy Wins Load Relief Auction

Demand Energy was a successful bidder in Consolidated Edison’s first-ever auction to provide load relief on peak power days in New York City.

Demand Energy will soon begin installing several megawatts of energy storage in Brooklyn and Queens, controlled by the company’s Distributed Energy Network Optimization System (DEN.OS) intelligent software. The project is part of Con Ed’s Brooklyn-Queens Demand Management program.

The energy storage project, which will come online in 2017, will delay the need for a new $1.2 billion substation. The program will use demand-side resources such as energy storage, energy efficiency and demand response. The project is a prototype for New York State’s Reforming the Energy Vision initiative to encourage the use of more distributed resources.

More: Demand Energy

NORTH DAKOTA

Tribe Blocks Access to Dakota Access Crews

Members of Standing Rock Sioux Tribe blocked crews working on the $3.8 billion Dakota Access pipeline that is to carry crude oil from North Dakota to terminals in Illinois.

Although the pipeline developers have received the necessary permits from state and regulatory agencies, they face continuing legal and political challenges. One was by the Standing Rock Sioux Tribe, which sued federal regulators in July, claiming the pipeline runs too close to sacred land and the tribe’s drinking water supplies. Tribe members blocked a road near their 2.3-million-acre reservation, backing up a line of 45 construction vehicles.

Work has already started on the 1,168-mile pipeline in other places in North Dakota, South Dakota and Illinois.

More: Associated Press

OKLAHOMA

Drop in Number of Earthquakes Could be Result of Regulation

Oklahoma has experienced a decline in earthquakes compared to last year, and some geophysicists believe that more stringent regulation of underground injection of wastewater from oil and gas drilling operations may deserve some of the credit.

According to the U.S. Geological Survey (USGS), Oklahoma experienced 448 magnitude 3.0 or greater earthquakes as of Aug. 10, compared to 558 for the same period last year. Robert Williams, with USGS, said the increased restrictions on wastewater injection and disposal could be one reason for the decrease, as well as the drop in oil and natural gas exploration.

More: USA Today

City Tests Smart Meters Before Making the Switch

City of Edmond officials in Oklahoma are conducting a pilot program to help determine whether the city should install smart meters for all 35,000 electric customers and 32,000 water customers. The pilot program could last from six months to a year before a decision is made.

In a 2011 feasibility study, consultants told city officials a total system, with all the possible extras, could cost $36 million over 15 years.

About 1.7 million smart meters were installed across Oklahoma in 2014.

More: The Oklahoman

PENNSYLVANIA

PUC Reliability Report Dings Penelec

A report by the Public Utility Commission says Penelec customers saw more power failures last year compared with consumers of electricity from other large companies in the state.

The report relies on data from quarterly and annual reliability reports submitted by electric distribution companies and details four benchmarks.

Penelec failed to meet any of the benchmarks but expects to improve reliability by 2018.

More: The Bradford Era

August 15, 2016

PGE Files Diablo Canyon Shutdown Request

By Robert Mullin

Pacific Gas and Electric filed with California regulators last week to shut down the state’s last remaining nuclear power plant by the end of 2025.

The application also asks the state Public Utilities Commission to approve a joint proposal that the utility forged with environmental, labor and anti-nuclear groups to replace output from the 2,240-MW Diablo Canyon facility with a portfolio of renewable resources, energy efficiency measures and energy storage.

Pacific Gas and Electric Files Diablo Canyon Shutdown Request — Diablo Canyon *Source: PG&E*

PG&E announced the closure in late June, saying the plant’s full output would no longer be needed in light of dramatic changes in California’s energy market, which increasingly is putting a premium on flexible resources over inflexible baseload generation. (See: PG&E to Shut Down Diablo Canyon, California’s Last Nuclear Plant).

In its filing, the utility also pointed out the uncertainty of its future supply needs, with customer demand being undercut by improvements in building efficiency, increased adoption of rooftop solar and the growth of alternative energy suppliers such as community choice aggregators (CCA).

“As a result of the rapidly changing California energy landscape, Diablo Canyon will not be needed at the end of the license period,” the utility wrote.

The joint proposal accompanying the filing includes three tranches to procure energy efficiency and greenhouse gas-free resources between 2018 and 2045.

The first tranche is intended to reduce load before Diablo Canyon retires through a competitive solicitation to add 2,000 GWh worth of energy efficiency to PG&E’s service territory by 2024. The company is seeking PUC authorization to recover $1.3 billion to administer the program over seven years through a “public purpose program” rate component.

Included in the second tranche is a solicitation for 2,000 GWh of carbon-free energy to be delivered between 2025 and 2030, with renewable resources, energy efficiency and other technologies eligible to bid. PG&E is seeking to recover part of the costs associated with this tranche from a “clean energy charge” allocated to the utility’s bundled electric and direct access customers as well as to CCA customers. Renewable procurement costs would also be recovered from an additional fee assessed on customers who depart from PG&E.

The third tranche includes PG&E’s voluntary commitment to increase its renewable portfolio standard to 55% over the 2031-2045 period — five percentage points above the current 2030 mandate.

The joint proposal also includes provisions for PG&E to recover costs related to winding down Diablo Canyon’s operations.

PG&E is asking the PUC to approve a two-way balancing account to implement yearly rate adjustments to recover the costs and allow the plant’s book value to be depreciated to zero by the time it closes. The utility is also seeking have ratepayers cover $53 million in costs previously incurred in efforts to renew the plant’s operating license beyond 2025.

PG&E has requested a decision by the CPUC by June 2017.

August 15, 2016

PJM Market Implementation Committee Briefs

Excess capacity expected to be released in the third incremental auction for the 2017/18 delivery year in February would likely clear at $0 under current rules, PJM’s Jeff Bastian told the Market Implementation Committee Wednesday.

To avoid that, PJM presented a proposal that would release excess capacity on an upward trajectory, ranging from 0 MW at $10.74/MW-day to all 10,017 MW being available at $144/MW-day or 1.2 times the Base Residual Auction clearing price.

That is, the RTO would retain more capacity at lower prices but be willing to release more at a higher price.

PJM must file its plans for releasing the capacity with FERC by November. Because of that time constraint, some members suggested advancing the PJM proposal to the Markets and Reliability Committee for a first read.

Among them were Jeff Whitehead of Direct Energy and Mike Borgatti, representing NextEra Energy. Both said they would be willing to forego their companies’ alternate proposals to support PJM’s solution.

At the July MIC meeting, Direct Energy had proposed using a sloped offer curve to create a price floor that would prevent supply resources from being able to cheaply buy out of their obligation at load’s expense. NextEra proposed PJM’s sell offer equal the transitional incremental auction adder that the RTO charges to load. (See “Members Debate Ways to Release Excess Capacity into Incremental Auction,” PJM Market Implementation Committee Briefs.)

Bastian said all three approaches are intended to preserve value for load.

“If the clearing price is zero, then you are releasing capacity commitments with no benefit going back to load,” he said.

The PJM proposal contains three parts. The first retains the status quo for how PJM determines the quantity and price at which it procures or releases MW in an incremental auction due to changes in load forecast or reliability requirements.

The second part, however, would release the 10,017 MW separately, according to the upward-sloping price curve.

Lastly, any of those separately released MW that did not clear would not be included in the determination of excess commitment credits.

“We would exclude this uncleared quantity from the quantity included in the first bullet,” Bastian explained.

Katie Guerry of EnerNOC said she was surprised by PJM’s new proposal, given that in July it had presented a plan to release capacity into the 2017/18 year using the same method FERC had approved for the 2016/17 delivery year, which yielded $4.79/MW-day.

“To hear PJM changing [its] position after the conclusion of that second incremental auction, after what we’ve been hearing from PJM for months now, is a little confusing,” Guerry said, adding that she was not comfortable with the issue being advanced yet to the MRC.

“PJM’s thinking has evolved,” Bastian said. “I wouldn’t say we had a position here. When we brought this forward again, we brought it forward as a discussion item. Our intent at this point would be to release it. We could go forward using the same method as last time. But if we use the same method, we’re likely to clear at zero, and that didn’t seem to make sense.”

Whitehead said PJM’s new proposal should not be a surprise, as the committee has been debating different approaches for several months.

“I feel this has been vetted here. I understand that you may not be happy with the outcome, but the opportunity for dialogue certainly occurred,” Whitehead said to Guerry.

“There’s a reliability tradeoff for these sales,” he said. “It is critical to recognize that we have the potential to sell back 10,000 MW of capacity. To do that and to know there’s a distinct possibility that most of those MW could clear close to zero … it’s counter-intuitive that in one auction we’re valuing capacity at $150, and, in the next instance, we’re valuing it at zero. The reduction in load’s cost is 1%, while giving up 5% of reliability — that should be concerning.

“It’s a lot of capacity, and my company’s position is we need to make sure we are putting the right value on those sales,” said Whitehead.

Independent Market Monitor Joe Bowring repeated his position that PJM should not buy more capacity than it needs and should not sell it back for less than it paid. But, he said, the PJM proposal goes in the right direction.

Still, Bowring said, “There’s no cap. There is no limit. There’s no reason not to hold onto that capacity, which was purchased for a higher price.”

In the end, committee Chair Chantal Hendrzak declared the item an official first read for the group.

Order 825 Progress

PJM staff announced their preliminary plans for implementing five-minute interval data for load, generation and shortage pricing.

For generation, PJM would use existing estimated or telemetry data and create five-minute profiles that correspond to hourly revenue-quality meter data already submitted. The five-minute telemetry data would be average and combined with a scaling factor for each five-minute interval profile associated with five-minute LMPs. The total of the 12 intervals would equal the hourly revenue-quality data. This is a protocol other ISOs are using, PJM’s Adam Keech said.

Order 825 doesn’t require load to provide five-minute data, so PJM plans to use flat profiling over the 12 intervals in an hour and associate that with five-minute pricing to determine load pricing. Demand response is also submitted hourly, so PJM would prorate such resources by interval for curtailments of less than an hour. PJM doesn’t have the granularity to use state estimator data for discrete DR, Keech said.

PJM wants to continue using megawatt-hour values and augment them with five-minute LMPs for pricing. The plan hasn’t yet been discussed with other RTOs, though, and stakeholders expressed concern that differences in each RTO’s plan might impact their interaction.

For shortage pricing, PJM introduced a problem statement to develop new curves that are complementary with the rules of Order 825.

While the order allows more time for initiating shortage pricing, PJM wants to implement it jointly with the load and generator changes because of concern that five-minute pricing could distort hourly prices, Keech said. PJM has been discussing this with other RTOs, particularly ISO-NE, and have come up with similar solutions.

Currently, PJM’s four curves are very similar and all have the same $850 penalty factor. The RTO currently addresses transient shortages — those expected to last a very short time —by easing reserve requirements slightly until expected supply arrives. Order 825 prohibits PJM from doing this, so the RTO wants to develop new demand curves that complement the requirements of the order.

Members Hear First Read on Plan to ‘Un-Nest’ Operating Parameters

The MIC will be asked at its September meeting to endorse one of two proposals on whether and how to “un-nest” operating parameter definitions to separate soak time from start time (see table).

The definitions are contained in Manuals 11, 15 and 28. (See “Members OK Operating Parameters but Urge Refinements,” PJM Markets and Reliability and Members Committees Briefs.)

NYISO to be Consulted on Changing Spot-in Service Allocation Methods

Joe Wadsworth of Vitol presented further discussion on how to improve the process of allocating spot-in transmission for energy imports from NYISO.

In April, the committee approved a problem statement and issue charge on the subject. (See “Allocating Spot-in Service for NYISO Imports to be Studied,” PJM Market Implementation Committee Briefs.)

Currently, the free but limited service is allocated on a first-come, first-served basis with no priority for participants who have cleared the NYISO market.

Wadsworth proposed removing PJM’s limit on requests for spot-in service and relying on NYISO’s real-time economic evaluation to determine which importers get spot-in service. He also proposed modifying some rules and timelines for the NYISO/PJM interface.

Wadsworth said talks are planned with NYISO and he would present their feedback at the next meeting.

Although no similar concerns have been expressed regarding the MISO seam, Bowring suggested the committee consider expanding the proposal to apply to all of the neighboring RTOs.

— Suzanne Herel and Rory D. Sweeney

August 15, 2016

Energy Wildcatter Hopes to Make His Mark in Emerging Mexican Market

By Tom Kleckner

With its electricity demand projected to grow 3 to 4% annually, the expected retirement of 10 to 15 GW of fossil plants, a commitment to add 1 GW of wind power annually and off-peak prices as high as $65/MWh, Mexico presents an appealing target to generation developers.

And Mannti Cummins wants a piece.

A certified public accountant by training, Cummins now calls himself a wildcat wind-energy developer, having developed more than 1,000 MW and $2.2 billion worth of wind projects in the U.S. and Mexico.

“Get in early, get in cheap,” he said in describing his strategy. “Hopefully, it’ll be a good market position with relatively few dollars spent.”

For now, however, Cummins and other developers are finding that a lack of transparency and uncertain rules are making their efforts anything but a sure bet.

Cummins, who grew up near the Gulf of Mexico, has made his home in Mexico for the past decade and speaks Spanish fluently enough to have completed a course in energy law from Mexico’s Escuela Libre de Derecho law school. He helped develop that country’s first two managed health care insurance firms and served as their CEO.

In his spare time, Cummins has been an avid surfer. He’s also been known to play Billy Idol’s “White Wedding” on his accordion.

Having made his mark in industries on both sides of the border, Cummins has jumped headlong into the Mexican energy market, which opened to national and international wholesale competition earlier this year.

Focus on Renewables

For the time being, much of the market’s focus is on renewable energy. Mexican President Enrique Peña Nieto in June joined President Obama and Canadian Prime Minister Justin Trudeau in pledging to generate half his country’s power from clean-energy sources by 2025, accelerating its 2013 pledge to produce 35% of its energy from renewable sources by 2024.

Cummins notes that Mexico’s definition of “clean-energy sources” does not include natural gas or nuclear energy. The Ministry of Energy’s National Electricity System Development Program projects Mexico will need more than 20,000 MW of clean energy over the next 15 years, part of an estimated $62.5 billion in private investment in the energy industry by 2018.

“Every year, Mexico has … to add 1,000 MW of wind power,” said Cummins, currently director of Energia Veleta, S. de R.L. de C.V. (which translates as wind vane energy) in Monterrey, Mexico.

Market Phase-In

Mexico’s wholesale market will be implemented in phases through 2018. It consists of short-term markets (day-ahead, hour-ahead, real-time and ancillary services), medium-term auctions (three-year energy and capacity contracts), long-term auctions, financial transmission rights auctions, a capacity-balance market and the 20-year clean-energy certiﬁcates — instruments equivalent to 1 MWh of energy from clean sources — market that Cummins and other developers have their eyes on.

In the first clean-energy auction in March, about 80 firms offered more than 200 bid packages, with contracts awarded to Enel Green Power, Acciona, Jinko Solar and other players.

Cummins said state-owned Comisión Federal de Electricidad (CFE), Mexico’s only utility, saw some solar projects bid as low as $40/MWh, lower than the utility had expected. All told, CFE awarded 5.38 million MWh of contracts, with almost 75% of those going to solar developers. A second auction will be held in September.

Because bidders were required to have a financial guarantee of about $40,000/MW to participate, Cummins lamented, the wildcatters were priced out.

“I wanted to bid in March, but I couldn’t find anybody to put up the guarantee,” Cummins said. “That would have required about $2 million, which I ain’t got.”

Cummins was riding in a Mexico City taxi as he spoke, on his way to a meeting with a fourth-level executive in the country’s energy department to discuss timetable issues. The man he was going to meet “is the guy that turns the crank,” the person who implements policy directives, Cummins said.

In order to place financial guarantees for the September auction, Cummins needs an interconnection, which requires a bond guaranteeing that upgrade costs will be paid, and a generation permit from Mexico’s Energy Regulatory Commission. And he must be ready to turn in reams of paper.

“Coordinating calendars for other permits … makes it tricky,” Cummins said. He planned to complete the paperwork by Aug. 29. “The [first official] deadline is Sept. 1. That’s a slim margin for error.”

It may not matter. Cummins said in a subsequent email exchange that an “unexpected change” in the auction’s evaluation criteria “most likely knock[s] us out as contenders in this auction as well.”

Growing Pains

Growing pains are to be expected in any immature market, but those pains have been amplified by Mexico’s emergence from a state-run monopoly. Vertically integrated CFE has long been the country’s only electric utility, much as Pemex controls the country’s oil industry. It is only now being restructured into generation, transmission and distribution firms.

“The market is open, and it has a single participant … CFE, which was the single participant before it opened,” Barbara Clemenhagen, Customized Energy Solutions’ vice president of market intelligence, explained at an Infocast conference in March. “If the statements for the initial 48 days are indicative, there’ s not much transparency and liquidity in the market.”

Clemenhagen said CFE is participating as both a buyer and a seller in the clean-energy auctions, covering the demand of its regulated clients and load centers. The utility was the only buyer for capacity, energy and clean-energy certificates in the last two auctions but was not allowed to sell because its generation companies do not exist yet.

El Centro Nacional de Control de Energía (CENACE), the grid operator, was an operating division of CFE, the vertically integrated national electric utility. CENACE became an independent system operator in August 2015.

CFE is also being restructured into different generation, transmission and distribution firms.

“The same guys who are on the CFE payroll in the morning are with CENACE in the afternoon,” Cummins said. “The independent part needs some time to set, since most CENACE folks were transitioned from similar posts in CFE.”

Grupo Fenix, which works with rural communities in Nicaragua to promote renewable energy, reforestation and sustainable development, also qualified as a market participant but has chosen not to participate.

“They pulled this thing together so fast, all the loose ends aren’t tied up,” Cummins said. “How long did it take ERCOT to get [its competitive market] going? The Senate bill passed in 1999 and it took 10 years to decide what was up.

“Wildcatter guys like us, we don’t mind navigating in an uncertain environment. But when you start putting hundreds of millions of dollars down, you better have everything locked up pretty good.”

Cummins said he would like to see more clarity in the market’s interconnection rules, the source of many of his current headaches.

“There needs to be coordination between the auction process and the interconnection process,” he said. “In ERCOT, you file your study and ERCOT comes in with theirs. There’s a date certain your study has to be done. Not in Mexico. That process and the auction timetables sometimes just don’t line up.”

The wildcatter would also like to see clean-energy generators create bilateral contracts outside the auction process with consumers, who will be required by Mexican law to buy 5% of their load from clean-energy sources in 2018.

“The rules in that market are uncertain and not definable for the amount of risk [involved],” Cummins said. “Those rules have not been ironed out.”

Compounding the problem, Cummins said, is the lack of a mechanism to balance load with generation and the requirement that private-generation companies purchase clean-energy certificates — even though clean-energy projects have yet to be built.

Clemenhagen said even when the rules are finalized, a lack of transparency makes it difficult to know who changed the rules and why. As of this spring, only 13 of 30 expected operating procedures and manuals had been released, and only one (the long-term auctions market) had been ﬁnalized.

“She’s not the only one [who feels that way],” Cummins said. “There are inconsistencies in the rules, gaps in the rules, downright confusion in the rules. The sheer volume of the rules … you have to have a person, or two or three, just to read the darn documents on a daily basis.

“It’s a haul, especially in a market like Mexico’s, where you have plenty of unknown unknowns,” he said.

Still, Cummins is making a go of it. His 148.5-MW Tres Mesas wind farm in the state of Tamaulipas, owned and operated by Oak Creek de México, is scheduled to be operational by the end of the year.

mexico energy — Tres Mesas *Source: Manti Cummins*

He also has four other projects in development in four states, Baja California Sur, Jalisco, Sonora and Zacatecas. That includes a 50-MW wind farm in Baja Sur, an island grid where all generation is supplied by fuel oil.

“We’re in so deep now,” Cummins said, “we don’t have a choice but to accomplish the goal.”