Another Cold Winter Helps Michigan Utilities in Q1

By Chris O’Malley

Extreme cold helped drive first-quarter earnings at two of Michigan’s largest gas-electric utilities, though neither DTE Energy nor CMS Energy enjoyed quite the bump it did during the polar vortex last year.

Moreover, operating revenue at DTE Energy fell 24% on losses in its energy trading business. DTE’s first-quarter earnings of $273 million ($1.53/share) compare to $326 million ($1.84/share) in the first quarter of 2014. Per-share earnings exceeded a $1.52 forecast by analysts polled by Thomson Reuters.

Operating revenue of $2.98 billion was down from $3.93 billion a year earlier and less than the $3.53 billion analysts had forecast.

In the first quarter, DTE’s energy trading unit lost $9 million, versus a profit of $42 million in early 2014. The company cited mark-to-market adjustments.

Operating earnings for DTE Electric were flat, at $136 million. DTE Gas earnings of $111 million were down 14%, from $129 million during the first quarter 2014 polar vortex.

During a conference call with analysts, DTE Energy executives held firm on full-year earnings-per-share estimates of $4.48 to $4.72.

“We’re off to a strong start across our portfolio of businesses,” Chief Financial Officer Peter Oleksiak said.

First-quarter net income of Jackson, Mich.-based CMS Energy fell nearly 1% to $202 million ($0.73/share). That compares with $204 million ($0.75/share) in the first quarter of 2014.

On a weather-normalized basis, however, earnings per share were 7% more than last year’s first quarter, CFO Tom Webb told analysts during a conference call.

CMS said it was holding to its 2015 earnings-per-share guidance of $1.86 to $1.89, in line with the company’s annual adjusted growth goal.

April 28, 2015June 15, 2023

Federal Briefs

The Bureau of Land Management is taking public comments on a gas processing plant that QEP Resources Inc. wants to build near LaBarge, Wyoming. The plant would process production from nearby natural gas wells, separating the raw feed gas into refined helium and marketable carbon dioxide and methane streams.

Refined helium product would be delivered to markets by commercial truck. Excess nitrogen would be vented to the atmosphere. Waste streams of hydrogen sulfide would be injected into a sour gas disposal well currently planned to be drilled close to the plant. Another well would be used for injecting waste water and four wells would be used to inject unsold carbon dioxide.

The plant would include about 16 miles of methane and CO2 pipelines, 13 miles of 230-kV transmission line and a substation. While some of the 355 acres for the project are on federal and state land, the majority is on land owned by QEP. The BLM is taking comments until May 20. Comments may be emailed to the bureau.

More: PennEnergy, BLM

Lawmakers Introduce Bill Targeting “Absurd” Fossil Fuel Tax Breaks

Sen. Bernie Sanders (I-Vt.) and Rep Keith Ellison (D-Minn.) introduced a bill that would kill tax breaks for fossil-fuel companies. They said the bills could save $135 billion over 10 years.

“At a time when scientists tell us we need to reduce carbon pollution to prevent catastrophic climate change, it is absurd to provide massive taxpayer subsidies that pad fossil-fuel companies’ already enormous profits,” Sanders said in a statement.

The “End Polluter Welfare Act” target federal subsidies for the oil, natural gas and coal industries, as well as grant programs for rail companies. It also calls for an increase in the royalties that coal, oil and gas companies pay for extracting oil and gas from federal land.

More: The Hill

No Changes Needed At Fuel Plant, NRC Says

The Nuclear Regulatory Commission gave a clean bill to a nuclear-fuel processing plant in Erwin, Tenn. The NRC’s two-year- licensee performance review at the Nuclear Fuel Services facility found that the plant was operating at a satisfactory level of safety and security.

The review singled out an incident in which an employee propped open two valves with a tool rather than holding them open according to regulations, but the infraction was deemed a low-risk event, the commission said. A separate chemical spill at the plant, earlier this spring, is still under investigation.

Nuclear Fuel Services is a subsidiary of Babcock & Wilcox Nuclear Operations Group.

More: WJHL-TV

FERC to Conduct Environmental Study Of Tennessee Gas Conversion Plan

The Federal Energy Regulatory Commission will prepare an environmental assessment of a plan by Kinder Morgan’s Tennessee Gas Pipeline to convert an existing pipeline to transport natural gas liquids collected from shale gas fields. The line was originally built about 70 years ago to move natural gas. It runs 256 miles through 18 Kentucky counties, into Tennessee. The current south-to-north flow will be reversed.

An environmental assessment could take as long as six months, and will look at construction methods, materials, and the pipeline path.

More: Lexington Herald-Leader

Environmental Group Opposing Ameren Nuke Plant License Extension

CallawaySourceNRC — Callaway Nuclear Station (Source: NRC)

A Missouri environmental organization is calling for the Nuclear Regulatory Commission to reverse its decision to grant a license extension to Ameren Missouri’s Callaway nuclear station. The Missouri Coalition for the Environment is appealing the NRC’s decision to extend Callaway’s operating license until 2044. The group cites pending legal challenges that could have an impact on the case.

More: St. Louis Dispatch

NRC Gives Peach Bottom Highest Rating in Review

Peach Bottom Atomic Power Station (Source: Exelon)

Exelon Nuclear’s Peach Bottom Atomic Power Station received the highest safety rating after a review by the Nuclear Regulatory Commission. The NRC announced its finding at a public forum held last week. The NRC senior resident inspector for the plant, Sam Hansell, told a small crowd that the plant on the Susquehanna River had only minor violations in 2014. “Peach Bottom is in a group of top-performer plants,” he said. “They get credit for running their plant safely.”

More: The Baltimore Sun

April 28, 2015January 23, 2024

MISO to Consumer Sector: No Money for You – UPDATED

By Chris O’Malley

CARMEL, Ind. — MISO has declined a request by the Public Consumer Advocates sector for $200,000 to help cover its legal costs in a fight over MISO transmission owners’ return on equity.

The decision was announced Wednesday at the MISO Advisory Committee meeting.

“We don’t have a mechanism to send them money,” said MISO General Counsel Stephen Kozey, adding that there was no show of stakeholder support for such funding.

The Public Consumer Advocates sector consists of both non-profit groups and government agencies that represent consumers in utility cases before state regulators.

It decided to enter the ROE battle — the sector’s first-ever litigation in a federal rate case — after settlement talks ordered by the Federal Energy Regulatory Commission between industrial customers and TOs broke down last year.

The consumer sector made the funding request at the Advisory Committee in February, saying it lacks the deep pockets for legal costs.

Robert Mork, deputy consumer counselor for the Indiana Office of Utility Consumer Counselor, said the consumer advocates have been supportive of MISO over the years. “We have to say we’re surprised and disappointed by MISO’s decision on this,” Mork said.

Appeal to Board

Mork raised the issue again during Thursday’s Board of Directors meeting, urging the board to ensure that ratepayer concerns are protected.

Mork said a letter Kozey sent to the advocates explaining MISO’s rejection “seemed to rely primarily on tallying up the sectors’ responses, and not in a very nuanced way at that.”

The letter reported that five sectors in addition to the consumer advocates commented on the request, with four — the Power Marketers and Brokers, Transmission Developers, Transmission Dependent Utilities and Transmission Owners — in opposition.

The Organization of MISO States took no position, despite acknowledging that the case “may have significant impact on customers throughout MISO, and it is valuable to have diverse viewpoints, including consumer advocates, represented before FERC.” Texas and Louisiana abstained from OMS’ vote.

Mork said Kozey’s response “raises concerns to our sector that MISO may not adequately appreciate its independence and stakeholder responsiveness” obligations under FERC Order 719, he said. “We would respectfully suggest that MISO needs to show that it understands that it has a clear obligation to look beyond the particular [views] of the sectors and to consider what is in the overall interests of the organization and the public.”

Mork added that his sector would continue to engage with MISO.

“We all have a shared interest that MISO-related issues appear to be dealt with so as to ensure the legitimacy of MISO and its processes.”

Mork didn’t elaborate on the group’s response to the funding denial but said that the consumer sector would have further discussions with MISO, OMS and FERC.

Neither any of the board members nor any stakeholders made comments on the issue.

MISO industrial customers initiated the ROE dispute last year, contending that transmission operators’ current base ROE — 12.38% except for American Transmission Co., at 12.2% — is too high (EL14-12). On April 3, the consumer advocates asked FERC for approval to amend the group’s intervention by adding allies from Arkansas, Kentucky, Louisiana, Montana and Illinois. (See MISO TOs Seek Base ROE of 11.39%.)

April 28, 2015June 15, 2023

NERC: Industry Needs More Time to Meet Clean Power Plan

By William Opalka

The U.S. electric industry will face reliability concerns in four years if the interim goals of the Environmental Protection Agency’s Clean Power Plan aren’t relaxed, the North American Electric Reliability Corp. said last week.

NERC released a reliability assessment of the CPP Tuesday that concludes EPA’s proposed 2020 targets — 80% of the total CO₂ emission reductions the agency seeks — can’t be reached in several regions.

The 69-page report provides additional ammunition for critics who have called for changes to the interim goals and the provision of a reliability “safety valve.” The report is NERC’s second on the impact of the EPA plan. Its initial review, released in November, examined EPA’s assumptions and provided a broad view of potential reliability risks. (See MISO, SPP: EPA Clean Power Plan Threatens Reliability, Needs Longer Compliance Schedule.)

Scenarios Analyzed

The new report examines in detail how the plan would impact the generation mix and resource adequacy. It also provides a high-level analysis of transmission needs and identifies major shortfalls of reactive power needed to maintain voltage stability. In addition to a business-as-usual baseline, NERC compared a scenario assuming state-by-state compliance with one allowing for regional compliance with interstate trading. It also conducted sensitivities on the impact of lower gas prices.

NERC concludes the plan will accelerate the transition in the generation mix as natural gas, wind and solar power replace coal. The report predicts about 60 GW of natural gas-fired generation will be added by 2020, rising to 80 GW by 2030. Coal retirements are projected to total at least 18 GW by 2020 and an additional 18 GW by 2030.

Much of the remaining coal fleet will have to change from baseload to seasonal and peaking use, making the plants less economic, NERC said. Between 14 GW and 22 GW of coal plants remaining in service after 2020 will be at risk because they would be operating at capacity factors of only 11% to 19%.

The report warns that new generators will be needed before the transmission and pipeline infrastructure to support them can be built. While most combined-cycle gas turbine plants go from conception to operation in an average of 64 months, transmission infrastructure can take from five to 15 years. Local and regional pipeline infrastructure will also need to be in place to deliver gas to the new plants.

“More time is needed to develop coordinated plans for this shift in generation and corresponding transmission reinforcement,” said John Moura, director of reliability assessments.

NERC noted there are regions where compliance will be easier, but says New York and the New England states in the Northeast Power Coordinating Council will need more than 7 GW of new capacity by 2020, with ERCOT in need of 11 GW over the same time frame.

The report also predicts major changes in transmission flows, with Canada tripling its exports to the U.S. and PJM-East shifting from being a net importer to a net exporter as generating units in Regional Greenhouse Gas Initiative states become more competitive with the imposition of carbon pricing nationwide.

MISO Central would reduce its exports to MISO North due to cheaper imports from Canada while increasing its exports to MISO South.

EDF Challenges Report

The Environmental Defense Fund disputed the report’s conclusions.

“NERC’s modeling uses unrealistic assumptions that are contradicted by what’s happening on the ground today,” Cheryl Roberto, EDF’s associate vice president of clean energy said in a statement.

NERC “fails to capture the great innovation happening now – with major investments in renewables, efficiency, natural gas and transmission infrastructure,” Roberto said. “NERC’s report also assumes flat-footed regulators, when the truth is regional and state-level regulators have repeatedly demonstrated they are up to the task of planning for future power needs. In short, NERC’s assessment does not take into account the transformation unmistakably underway in our electric system.”

April 28, 2015June 15, 2023

PJM Considering Change to Day-Ahead Deadlines in Response to FERC Gas Schedule Order

By William Opalka, Chris O’Malley and Rich Heidorn Jr.

PJM is considering changing its day-ahead market schedule in response to the Federal Energy Regulatory Commission’s April 16 ruling revising the interstate gas nomination timeline.

Other RTOs’ reactions varied, with ISO-NE saying it has no plans to change its schedule and NYISO looking to respond to its neighbors. MISO stakeholders will discuss the issue Friday, while an SPP task force is expected to make recommendations on any changes by July.

FERC moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (12:30 p.m. to 2 p.m. ET). It also added a third intraday nomination cycle (RM14-2). (See FERC Approves Final Rule on Gas-Electric Coordination.)

In response, PJM is considering moving up its day-ahead schedule by three hours, Adam Keech, senior director of market operations, told the Markets and Reliability Committee on Thursday.

PJM’s day-ahead market results currently are published at 4 p.m. ET, which would not provide enough time for selected generators to purchase gas, Keech said.

PJM is proposing that day-ahead offers close at 9:30 a.m. ET, with results published no later than 1 p.m. That would allow at least one hour for gas generators selected to run the next day to purchase fuel before the timely nomination cycle deadline.

The rebid period and reliability unit commitment (RUC) also would be moved up, running from 1 p.m. to 4:30 p.m., with results published by 6 p.m., allowing at least one hour for gas nominations before the evening nomination cycle deadline, which FERC left unchanged.

The changes would condense the day-ahead market solution window to 3.5 hours.

Joe Wadsworth of Vitol asked if PJM would be coordinating its changes with neighboring regions. He said moving PJM’s day-ahead deadline to 9:30 a.m. could inhibit trading with NYISO, which publishes its day-ahead results at about 9:30 a.m. That could hurt day-ahead convergence along the NYISO-PJM seam, he said.

Wadsworth said PJM also needs to consider that liquidity in the next-day gas markets sometimes doesn’t occur until after 10 a.m. on high gas-demand days. In such circumstances, there may be little or no natural gas price transparency prior to PJM’s day-ahead market bid deadline, he said.

Ed Tatum of Old Dominion Electric Cooperative suggested PJM coordinate the changes through the ISO/RTO Council and consider changing the start of the electric day.

Keech said FERC’s order neither mandates nor precludes changes to the electric day.

Keech’s comments came during a first read of a proposed problem statement to respond to the FERC order. Although the initiative won’t come up for a vote until the May 28 MRC meeting, PJM will conduct an educational session following the May 6 Market Implementation Committee meeting.

PJM and other regions must make compliance filings — adjusting their tariffs to comply with the final rule or explaining how their current rules are compliant — by July 23.

NYISO

“Because electricity markets are interdependent, the NYISO’s response to FERC’s order will need to account for its neighbors’ compliance efforts,” NYISO spokesman David Flanagan said. “If no changes are determined to be necessary, FERC’s decision will provide New York generators an additional hour-and-a-half to nominate the gas they require following the posting of the NYISO’s day-ahead market. FERC’s order also will increase the gas procurement flexibility available to New York generators that participate in the NYISO’s real-time market.”

MISO

MISO spokesman Andy Schonert said the RTO is “working internally and with stakeholders to figure out how we will respond to FERC’s order.” The Electric and Natural Gas Coordination Task Force will discuss the issue in a meeting May 1.

SPP

SPP spokesman Tom Kleckner said the RTO’s Gas Electric Coordination Task Force discussed the FERC ruling at a meeting Thursday and will be making a recommendation to SPP’s Board of Directors at the board’s July meeting.

“The [task force] is evaluating what changes can be made to the day-ahead and reliability unit commitment timelines,” Kleckner said. “It will be up to our stakeholders to make any changes to our timeline that are presented to the board.”

ISO-NE

ISO-NE, which shifted its day-ahead market schedule two years ago to align with the natural gas trading day, believes it is already in compliance with the FERC rule, spokeswoman Marcia Blomberg said.

“However, we are very disappointed at the decision not to change the gas day,” Blomberg said. “We continue to believe it would have been a material improvement to reliability. Without the change, obtaining fuel in order to meet their obligations will be more challenging for generators during upcoming winters. We are supportive of the change to the timely nomination cycle, which will help owners of gas-fired generators incrementally by improving their ability to timely nominate and schedule gas.”

April 28, 2015

PJM Members Tighten Lost Opportunity Cost Rules; Tech-Specific Eligibility Retained

By Suzanne Herel

WILMINGTON, Del. — PJM stakeholders last week approved tighter rules on generator lost opportunity costs but rejected a proposal to limit eligibility to the most flexible combustion units.

The rules concern compensation for combustion turbines that are scheduled in the day-ahead energy market but not committed in real time.

The vote by the Markets and Reliability Committee on Thursday was a partial setback for PJM and Independent Market Monitor Joe Bowring, who said current rules provide incentives for units to offer and clear in the day-ahead market but not in the real-time market.

PJM and the Monitor won a change preventing combustion turbines from receiving start-up and no-load costs when they do not run in real time — correcting what Bowring called “an algebra mistake” that resulted in generators receiving payments for costs they did not incur.

The change — including no-load and start-up costs as avoided costs in LOC calculations — was a reform the Monitor had sought since 2012. PJM has estimated the change could reduce LOC payments by about $40 million annually.

‘2×2’ Rule Rejected

The Energy Market Uplift Senior Task Force also had approved a proposal that would have allowed only the most flexible “2×2” CTs — those with start-up plus notification times and minimum run times of two hours or less — to receive lost opportunity costs if they are not dispatched in real time after clearing the day-ahead market.

Resources with start-up plus notification times or minimum run times of more than two hours would not have received lost opportunity payments unless PJM barred them from running in real time to avoid transmission overloads or other reliability problems.

But the task force’s proposal received less than 60% support in a sector-weighted vote of the MRC, short of the two-thirds minimum for passage.

An alternate motion that retained the current technology-specific LOC eligibility rules — combustion turbines and combined-cycle plants operating in simple-cycle mode — was then approved with nearly 92% support and a round of applause.

The MRC last month tabled the task force’s proposal, sending it back for more discussion, after some members, including Ed Tatum of Old Dominion Electric Cooperative (ODEC), complained that the 2×2 requirement was too restrictive. (See PJM Tables Rule Change on CT LOCs.)

Several proposed amendments emerged from the task force’s April 17 meeting: one by Dominion Resources, allowing for start-up costs to be paid if a unit operates in real time at PJM’s direction during any portion of its “temporally contiguous” commitment period; one from PJM clarifying the definition of “temporally contiguous”; and one from ODEC that would have extended LOC eligibility to 2×5 units with minimum run times of up to five hours.

Economic Choice

“We believe units with greater than a two-hour minimum run time are valuable to dispatch,” Tatum said. “We should be making decisions on units’ capability and not on an algorithm’s limitations.” (See PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs.)

Bowring disagreed. “I don’t agree there is any physical basis for any minimum run time. It’s not required by manufacturers … it’s typically an economic choice,” he said. “I would suggest, if anything, that two hours is too long, not too short.”

Bowring added, “Part of the reason we got into this problem in the first place is PJM wasn’t really looking out four or five hours. Five hours is nowhere near flexible.”

Neither amendment by Dominion nor ODEC was cleared as “friendly,” so membership voted on the main EMUSTF proposal, which failed.

Susan Bruce of the PJM Industrial Customers Coalition then made what became the winning proposal, suggesting that the language regarding LOC eligibility be returned to the status quo and considered for approval along with Dominion’s amendment and PJM’s definitional clarification.

“My understanding is that [the 2×2 issue] was a bit of a surprise to some people,” she said. “That will move us past this issue.”

PJM’s Adam Keech, director of wholesale market operations, said that regardless of a mandated minimum run time, PJM will be making procedural changes “because we think we can do better,” noting that the RTO paid $25 million in lost opportunity costs in February. “We’re going to look at less flexible CTs, with lead times eight to 10 hours, and run them more often,” he said.

Because the less flexible units will retain their LOC eligibility, committing them in real time will ensure they are paid based on LMPs instead of being compensated via uplift.

Because the day-ahead payments to the units are a sunk cost, the less flexible units in many cases become essentially a “free resource” to PJM operators, Bowring explained.

After the meeting, Tatum said he was pleased with the vote. “We’re good for now — until the next shoe drops,” he said.

April 28, 2015June 15, 2023

ISO-NE May Delay DR Integration into Markets

By William Opalka

ISO-NE is considering delaying full integration of demand response into its markets by a year due to uncertainty about the Federal Energy Regulatory Commission’s authority over the resource.

A 33-page Markets Committee contingency plan released April 17 suggests not implementing DR until 2018 because of the time needed to develop procedures once the issue is resolved.

The U.S. Supreme Court was scheduled to consider FERC’s appeal of the D.C. Circuit Court of Appeals decision threatening the agency’s jurisdiction at its conference Friday. But no decision was announced Monday and the court said no news is likely for at least a week.

The D.C. Circuit vacated FERC Order 745, which set rules for compensating DR in RTO energy markets, saying the commission had intruded on state jurisdiction (Electric Power Supply Association v. Federal Energy Regulatory Commission). There is disagreement over whether the ruling also voids FERC jurisdiction over DR in the capacity and ancillary services markets. FERC filed its appeal with the Supreme Court in January. (See FERC Files EPSA DR Appeal with Supreme Court.)

“Without direction from the U.S. Supreme Court and the FERC, the region’s next steps are uncertain,” according to ISO-NE’s plan. “Possible scenarios range from maintaining an approach that is fairly consistent with the status quo, to allowing demand response participation solely in the capacity and ancillary services markets, or to removing demand resources from the supply-side of the wholesale market platform altogether.”

If the Supreme Court grants FERC’s request for a writ of certiorari, ISO-NE said, a ruling is not likely before mid-2016. Then FERC must interpret how the court’s direction impacts the integration of DR in wholesale markets.

“In addition to the potentially protracted legal process in this case, it is also unclear how narrowly or broadly the decision in EPSA will be interpreted — primarily by the commission, but potentially by the U.S. Supreme Court as well,” the plan says.

ISO-NE had planned to implement full integration of DR into the energy and reserves markets by June 1, 2017, a transition it says will require at least two years of modifications to its software and system infrastructure.

“The ISO would be at least one year into the project to meet the June 1, 2017, implementation date before knowing the Supreme Court’s ultimate decision,” the plan says. “And for all of the time, money and effort expended up to that point, the Supreme Court may nevertheless uphold the D.C. Circuit’s previous ruling. Substantial resources will be wasted if the ISO moves forward to fully integrate demand response into the energy and reserves market by June 1, 2017, and the Supreme Court ultimately upholds EPSA.”

The Markets Committee will discuss the issue when it meets May 5-6.

FERC last month rejected as premature PJM’s contingency plan to include demand response in its capacity auctions in the event the EPSA ruling is allowed to stand. (See FERC: PJM Demand Response Stop-gap Measure ‘Premature’.)

April 28, 2015January 3, 2024

State Briefs

Dynegy CEO: Exelon Bill Endangers Jobs, Plants

Legislation proposed by Exelon that would impose a customer surcharge to provide more revenue for its Illinois nuclear fleet would put jobs at risk at competing coal-fired power plants, Dynegy CEO Bob Flexon said. “It’ll have a severe economic impact on jobs downstate,” he told Crain’s Chicago Business, placing Dynegy’s plants “more at risk for shutdown.”

“What I would like the Legislature to avoid is disrupting the market by introducing a subsidy for one generator at the expense of other generators,” he said. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)

More: Crain’s Chicago Business

INDIANA

Small Railroad Wants to be Heard in IPL Fuel Switch

Indianapolis Power & Light wants to switch its Harding Street plant from coal to natural gas. Cleaner fuel, more modern plant, better reliability, right? Who would complain?

Well, the small railroad that last year delivered 1 million tons of coal to the plant might. The Indiana Utility Regulatory Commission has recognized Indiana Rail Road Company to be an intervenor in the case. “This conversion will have a substantial, adverse financial impact,” the company wrote. The status as intervenor will allow it to cross-examine IPL witnesses. The rail company has not said whether it will try to stop the fuel conversion.

More: The Indianapolis Star

KENTUCKY

Landfill Project Will Generate Electricity from Methane Gas

The East Kentucky Power Cooperative plans to begin construction next month on a landfill-gas power plant after receiving approval from the Kentucky Public Service Commission.

The facility at the Glasgow Regional Landfill, which will generate electricity from methane gas produced from buried trash, could be operating by September. Other landfills in the state have embarked on such projects over the past decade.

EKPC, comprised of 16 owner-member distribution cooperatives, will purchase the methane gas from the city-owned landfill, and Farmers Rural Electric Cooperative Corp. will buy the electricity produced from the facility.

More: Glasgow Daily Times

MARYLAND

Hogan to Sign Bill Opening Transmission Construction to Non-Incumbents

Gov. Larry Hogan is scheduled to sign a bill Tuesday opening transmission construction to non-incumbent transmission developers.

Senate Bill 460 authorizes persons other than “electric companies” to obtain a certificate of public convenience and necessity (CPCN) to build overhead transmission at or above 69 kV and to obtain land access through condemnation proceedings. Under current law, that authority was limited to existing electric distribution companies — companies already delivering power to retail customers. The bill allows a transmission developer with a regionally cost-allocated project to obtain a CPCN if the Public Service Commission finds the permit is in the best interest of state residents.

The bill was backed by LS Power and NextEra Energy, two competitive developers seeking to gain business as a result of the Federal Energy Regulatory Commission’s Order 1000, which eliminated incumbent transmission developers’ federal rights of first refusal (ROFR). Order 1000 does not bar state ROFR preferences, but FERC Chairman Norman Bay has suggested such laws may be unconstitutional. (See FERC Rejects Rehearing Request on SPP Order 1000 Filing.)

More: Md. Department of Legislative Services

MICHIGAN

Democrats Propose Bill to Double Renewable Standards

While Republicans in Lansing are looking to gut or abandon the state’s renewable energy standard, Democrats are seeking passage of a bill that would double the clean energy standards. The bill, “Power Michigan’s Future,” was introduced last week and now heads for Republican-controlled committees.

The legislation would double the renewable portfolio standard, to 20% by 2022, while also increasing energy efficiency standards to 2% of a utility’s annual sales by 2019.

More: Midwest Energy News

Detroit Zoo Energy Plans: 400 Tons of Animal Manure

The Detroit Zoo is raising funds for a proposed power generator that would be fueled from something it has plenty of: animal manure. It is using an online crowdsourcing site – Patronicity.com – to help it obtain $55,000 in funds to match an offer by the Michigan Economic Development Corporation.

The zoo wants to build a biodigester that would capture methane from the manure to generate both heat and power for the zoo’s 18,000-squre-foot Ruth Roby Glancy Animal Health Complex. The zoo estimates it could save between $70,000 and $80,000 a year in energy costs. “The biodigester will turn one of our most abundant resources – manure – into energy, and represents a significant step on our green journey,” said Detroit Zoological Society CEO Ron Kagan.

More: MLive

NEBRASKA

Wind Energy Credit Bill Advances in Legislature

A bill that would create a wind energy tax credit moved forward last week with a 25-3 vote in the Senate. The bill would provide for a 1-cent tax credit per KWh of power produced. The credit would decline by a tenth of a cent every two years, and then end after 10 years. The federal wind energy tax credit, which expired last year, was 2.3 cents per KWh.

The bill’s sponsor, Sen. Jeremy Nordquist of Omaha, said the wind industry is ready to step in to replace production that will be lost from coal-fired plants being forced into retirement by federal emissions standards. The state has a high amount of potential wind energy, but ranked only 18^th in the nation in production while neighbor Iowa was first.

Iowa is one of six states with state production tax credits, according to a report last year by the Iowa Department of Revenue. “We need to be in the game,” Nordquist said. “Right now, without a [state] production tax credit, we are not in that game.”

More: Omaha World-Herald

NEW JERSEY

BPU Investigating JCP&L’s Operations, May Order Audit

The Board of Public Utilities has ordered its staff to examine Jersey Central Power & Light’s operations, finances and customer service, and indicated that the initial probe could extend into a full audit. The team conducting the probe is expected to report back to the board by its next meeting in May.

JCP&L has been the target of frequent criticism for its outages. The FirstEnergy subsidiary was handed a blow earlier this year when the BPU signed off on a rate case that reduced revenue by $115 million.

While JCP&L has upgraded substations to improve reliability, regulators have said the company is still under the microscope. “Even today, there lingering concerns about operations and management of the company,” said BPU President Richard Mroz.

More: NJSpotlight

Three N.J. Utilities Issue RFPs To Increase Solar Certificates

While not ready to build their own solar facilities, three utilities in New Jersey are seeking power purchase agreements with solar generators for about 80 MW of solar capacity. Atlantic City Electric, Jersey Central Power & Light and Rockland Electric Company are looking to secure Solar Renewable Energy Certificates to satisfy state mandates.

The three-year SREC program, certified by the Board of Public Utility’s Office of Clean Energy, awards one SREC for each MWh of solar generation. ACE is looking for 23 credits, JCP&L is in the market for 52 credits and Rockland needs 4.5 credits.

More: PV Magazine

NEW MEXICO

PRC Nixes Public Service’s Plan To Shutter San Juan Unit

The Public Regulation Commission’s refusal to allow Public Service Co. of New Mexico to shut down one half of its coal-fired San Juan Generating Station to meet federal emissions standards could spell trouble for the plant’s future, according to the company.

Public Service wants to retire two of the plant’s four units, and install emissions controls on the other two. While the hearing examiner agreed to closing the units, he nixed the company’s proposal to absorb 132 MW of excess coal capacity in one of the remaining two units. The company said its plan is necessary because some of the plant’s co-owners will pull out in 2017.

“The consequences of such a decision will likely lead to a collapse of the restructuring of the San Juan ownership interests … and ultimately endanger continued operations at San Juan,” the company wrote in a filing last week. If Public Service has to find outside sources for the lost generation, rates could increase for customers, it said.

More: Albuquerque Journal

NEW YORK

Anti-Fracking Report Due Out Soon

A several-thousand-page document that will lay out the rationale for prohibiting hydraulic fracturing will be released soon, state Environmental Conservation Commissioner Joseph Martens said. The Supplemental Generic Environmental Impact Statement will end seven years of study that paves the way for Martens to issue an order preventing large-scale fracking.

In December, Martens said he would move to prohibit high-volume fracking “at this time” after state Acting Health Commissioner Howard Zucker issued a report recommending against proceeding, citing concerns about health risks and gaps in science.

To formalize a ban, the state Department of Environmental Conservation has to complete the environmental impact statement. State law mandates the document must be available for public review for at least 10 days before Martens issues a “findings statement,” the legal document that would finalize the state’s decision.

Poughkeepsie Journal

Caithness Long Island Says 2nd Plant Could Save $192 Million a Year

Caithness Long Island Energy, which already operates a 350-MW plant in the center of Long Island, released a study that says construction of a second plant could lower regional energy costs up to $192 million a year.

The company said its proposed 750-MW Caithness II plant in Yaphank would also decrease the island’s dependence on power imports and on older plants. The company released the report after PSEG Long Island, operator of the local distribution company, announced that no new sources of power were necessary until 2024.

Caithness President Ross Ain called PSEG’s analysis “one-dimensional” and said it didn’t take into account other savings from both the proposed plant and from Caithness I. PSEG Long Island’s parent company also produces power that would be in competition with the Caithness project.

More: Newsday

NORTH CAROLINA

Most Wells Near Duke Ash Ponds Show Contamination

State environmental regulators issued health warnings after some tests of private water wells near Duke Energy’s coal ash ponds showed contamination. The Department of Environment and Natural Resources said that 87 of 117 test results mailed recently to property owners cited contamination that exceeded state water safety standards.

The state indicated that the water would pass federal standards for municipal water supplies. Nevertheless, the state included warnings not to use the water for drinking or cooking.

While the tests have not yet shown a direct link between the coal ash ponds and the contaminants, many of the contaminants were those often found in coal ash, such as toxic heavy metals. Duke said it believes the high levels of contaminants are naturally occurring. “Based on the test results we’re reviewed thus far, we have no indication that Duke Energy plant operations have influenced neighbors’ well water,” the company said.

More: The Charlotte Observer

Officials Approve Offshore Seismic Surveys With Some Caveats

The state Division of Coastal Management gave the go-ahead for seismic surveys off the North Carolina coast by two oil and gas exploration companies.

Although Spectrum Geo Inc. and GX Technology now have state permits, they still need approval from the Bureau of Ocean Energy Management and the National Marine Fisheries Service. The state division also set other conditions, such as conducting the surveys at times that don’t conflict with recreational fishing tournaments, avoiding certain protected habitats, and following federal mitigation methods to reduce or eliminate impacts to marine life.

More: Carteret County News-Times

Attempt to Scale Back RPS Foiled by House Vote

A House committee voted against an attempt to roll back renewable portfolio standards. House Bill 681 would have allowed utilities to freeze the amount of renewable energy they procure at 6% for the next three years. The current Renewable Energy and Energy Efficiency Portfolio Standard requires utilities to obtain 12.5% of their energy from renewable sources by 2021. The bill was defeated in committee 15-14.

More: WRAL

Duke Energy Moves Ahead With N.C. Solar Construction

Duke Energy is on track to complete three more utility-scale solar projects by the end of the year as part of a $500 million investment in North Carolina solar: the 65-MW Warsaw facility in Duplin County; 40-MW Elm City plant in Wilson County; and the 23-MW Fayetteville Solar Facility in Bladen County.

Duke is also building a 13-MW solar plant at Marine Corps Base Camp Lejeune. The company said last week that it will employ more than 900 workers on the plants at the peak of construction.

More: The Charlotte Observer, Duke Energy

PENNSYLVANIA

PUC Gives Initial Approval To New AEPS Regulations

The Public Utility Commission voted unanimously to revise the state’s Alternative Energy Portfolio Standards with new rules for net metering customers. The rules would allow “customer-generators” to produce up to 200% of their annual power needs, receiving retail prices for any excess they sell to the grid. The rules also would reduce PUC deadlines for approving net metering applicants.

Final approval is pending a comments session. The AEPS requires distribution companies and generation suppliers to source 18% of electricity from alternative sources by 2021.

More: The Philadelphia Inquirer, PUC

FirstEnergy’s Bruce Mansfield Plant Tagged with Notice of Violation

The Department of Environmental Protection issued a notice of violation to FirstEnergy Corp. for emissions at its Bruce Mansfield coal-fired plant in Shippingport. The DEP said that the plant’s Unit 2 stack exceeded emissions limits earlier this month. The NOV did not identify the emissions.

Workers at the plant found a leak in a duct and repaired it, a plant spokeswoman said. A DEP spokesman said union employees at the plant brought the issue to the attention of state regulators, and that “served as a way to gets us out there.”

More: Pittsburgh Post-Gazette

VIRGINIA

Dominion to Close All Ash Ponds in Virginia

Dominion Virginia Power said it will be closing all ash ponds at its Virginia power plants. The announcement came following the finalization of coal-ash disposal rules by the Environmental Protection Agency.

Virginia is the northern neighbor of North Carolina, which has been the scene of coal-ash legal action and legislation following a massive spill of toxic coal ash from a retired Duke Energy plant on the border of the two states. Dominion said it would close coal ponds at its Chesterfield Power Station near Richmond, the Bremo Power Station in Fluvanna County, the Chesapeake Energy Center in Chesapeake and the Possum Point Power Station in Prince William County.

The company said the ponds would be drained and sealed with a liner that would covered with a 2-foot layer of earth.

More: The Roanoke Times

McAuliffe Signs Clean Energy Bills on Earth Day

Gov. Terry McAuliffe signed several bills aimed at encouraging clean energy production, energy efficiency and jobs production:

- - HB 2267/ SB 1099: A bill creating the Virginia Solar Development Authority, which aims to spur construction of solar facilities;
  - HB 1950/ SB1395: Doubles allowable generation capacity of a solar net energy metering facility;
  - HB 2237: Authorizes utility cost recovery for construction or purchase of a solar facility with capacity over 1MW and establishes that 500MW of solar generation are in the public interest;
  - SB 1331: Clarifies how costs are evaluated by the State Corporation Commission to increase approval of natural gas energy efficiency programs;
  - HB 1446 /SB 801: Expands the Property Assessed Clean Energy (PACE) program, which creates loan programs for localities to finance energy efficiency projects on commercial buildings using private capital; and
  - HB 1843/ SB 1037: Extends $500 per job Green Jobs Tax Credit for three years to July 1, 2018

Some environmentalists applauded the move, but said more action is needed. “The fact that we’re celebrating Earth Day by witnessing several pieces of clean energy legislation get signed into law is proof of the growing movement in Virginia demanding solutions to climate change,” said Dawone Robinson of the Chesapeake Climate Action Network.

“Virginia currently has only 11 MW of solar installed, and that figure is embarrassingly low, especially compared to our neighbors. Virginia has as much or more solar potential than Maryland and North Carolina, yet those states have more than 200 MW and 950 MW of solar currently installed respectively thanks to much stronger state policies.”

More: Gov. McAuliffe, Chesapeake Climate Action Network

WISCONSIN

Contested Transmission Line Gains PSC Approval

The Public Service Commission last week approved the Badger-Coulee transmission project, and now land agents are fanning out to acquire the easements upon which it will be built. The 345-kV, $580 million line is a joint venture of Xcel Energy and American Transmission Co.

With the PSC’s approval, the companies received permission to pass the cost of the line on to consumers across the Midwest. The line is part of a larger project, the CapX2020, which will run across Minnesota and Wisconsin.

Construction work on that line is already underway. ATC and Xcel say the lines will provide a way to deliver cheaper wind-generated power to consumers.

More: Lacrosse Tribune

Alliant to Build $750 Million Gas-fired Plant in Wisconsin

Alliant Energy Corp. is seeking authority to build a $750 million combined cycle gas plant in Wisconsin, its first application for new generation since regulators rejected its 2008 proposal to build a coal-fired plant. The company is also proposing to build a new 2-MW, $9 million solar facility next to the gas plant.

The solar facility, if approved and constructed, would be the second largest in the state. The proposed gas-fired plant would be rated at about 700 MW. The proposal for the new complex coincides with Alliant’s plans to retire a coal-fired facility in Cassville, Wis. and coal boilers in Sheboygan to comply with an environmental settlement reached with federal regulators several years ago.

More: Journal Sentinel

April 28, 2015

PJM Markets and Reliability Committee Members Committee Briefs

The Markets and Reliability Committee approved Tariff and manual revisions regarding PJM’s use of sampling to measure and verify residential demand response.

The new measurement method was originally endorsed at the Jan. 22 Members Committee meeting. Thursday’s vote approved the inclusion of an additional transition year because of delays in filing the new method with the Federal Energy Regulatory Commission.

PJM now expects to make the filing in late April. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25, 2014.)

Tariff Harmonization Senior Task Force Charter Approved

The MRC approved the draft charter of the Tariff Harmonization Senior Task Force, formed to address inconsistencies and discrepancies in PJM’s governing documents. There was one abstention and one vote against the measure. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

Regional Planning Process Senior Task Force Placed on Hiatus

On first reading, MRC members approved the Regional Planning Process Senior Task Force’s recommendation directing the Planning Committee to develop guidelines for considering generation interconnection projects as drivers under the multi-driver transmission project approach.

The MRC also agreed to place the task force on hiatus, available to be returned to operation if needed based on future rulings by FERC.

Manual Change Endorsed

The MRC approved changes in Manual 14D: Generator Operational Requirements to reflect a recent advisory from the North American Electric Reliability Corp. on generator frequency response requirements. PJM sent Generator Operators a survey regarding governor dead band settings, droop setting and mode of operation on April 3. PJM will compile the responses, due June 3, and share the data with NERC.

FTR Auction Clearing Deadlines, Trading Periods Approved

The Members Committee approved minor “non-substantial” provisions regarding financial transmission rights’ auction clearing deadlines and trading periods.

April 28, 2015

Quebec-NYC Tx Line Clears Final Regulatory Hurdle

By William Opalka

A 1000-MW merchant transmission line that would deliver Canadian hydropower to New York City has completed its federal environmental review, clearing the way for construction.

The U.S. Army Corps of Engineers on Tuesday issued a permit to Transmission Developers Inc. that allows the Champlain Hudson Power Express project to be placed in U.S. waters along the proposed route. The entire 333 miles from the Quebec border to the Astoria neighborhood in Queens will be underground or underwater, including sections beneath Lake Champlain and the Hudson River.

TDI said the project has secured all of the federal and state siting permits necessary to proceed with construction, which could start next year. The permit authorizes TDI to construct the project under Section 10 of the Rivers and Harbors Act and Section 404 of the Clean Water Act.

The estimated $2.2 billion project would boost Canada’s interest in exporting electricity to New York and New England. (See Hydro-Quebec Seeks to Boost Exports to Northeast.)

“The terms of the permit reaffirm that our project will take appropriate steps to protect New York’s environmental and commercial resources, and we are excited to have moved substantially closer to the moment when we will begin to deliver cleaner, lower-cost power to New York’s residents and businesses,” TDI CEO Donald Jessome said in a statement.

The project has been under development since 2008. Its proponents claim it could reduce energy costs for consumers and businesses by $650 million a year.

The Independent Power Producers of New York, a trade association whose members would be in direct competition with imported energy sources, opposed the project. IPPNY insists the project is not financially viable without subsidies from Canadian power producers and an above-market-rate contract with New York utilities transmitting the energy.

The New York Public Service Commission has rejected those claims.

TDI plans to finance the project through private equity and support from shippers and contractors. TDI’s lead investor is the Blackstone Group.