PJM on Friday asked FERC to authorize cost responsibilities for $687 million in upgrades included in a revised Regional Transmission Expansion Plan approved by the Board of Managers in October (ER16-319).
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The cost allocations would become effective Feb. 11. Transmission customers have 30 days to submit comments about the proposed charges.
The upgrades address reliability issues or economic constraints, all on lower voltage facilities.
Included are 11 market efficiency projects, estimated at $59.3 million, which are expected to produce savings of $815 million over 15 years. They were selected from among 93 proposals, 58 from nonincumbent transmission developers.
New baseline reliability projects totaled $580.5 million. An additional $47.7 million was authorized for changes to previously approved baseline projects.
New York officials and others last week asked FERC to rehear an order that exempted renewable generation and self-supply resources from buyer-side mitigation rules in the state’s installed capacity market (EL15-64).
But several parties who sought the exemption in May say the commission’s order will stifle development of the very resources it is trying to protect. Petitioners representing power generators, meanwhile, sought to reverse or limit the exemptions.
“The commission adopted a renewable generation exemption that is unduly restrictive because it is limited to a narrowly defined population of intermittent renewable resources, and further constrains the exemption with an annual cap on new eligible renewable capacity,” said the original petitioners, the New York Public Service Commission, the New York Power Authority and the New York State Energy Research and Development Authority. “Moreover, the commission declined to adopt a general exemption for demand response resources.”
The petitioners were joined by New York City, the Natural Resources Defense Council and intervenors representing large commercial and industrial customers.
The order stated that a renewables cap should be developed through a stakeholder process at NYISO. The petitioners say they want no cap imposed. They also objected to the exclusion of demand response resources.
In other filings:
Astoria Generating, TC Ravenswood, NRG Energy and Cogen Technologies Linden Venture want to eliminate the self-supply exemption, saying that FERC did not identify evidence that it would not suppress capacity market prices.
The Independent Power Producers of New York and the Electric Power Supply Association asked the commission to bar state entities such as NYPA from using the self-supply exemption, saying they have ”demonstrated a strong incentive and ability to subsidize new entry to suppress ICAP prices.”
Transmission owners Consolidated Edison, Central Hudson Gas & Electric, Rochester Gas & Electric and New York State Electric and Gas requested a rehearing because there was no inclusion of demand response resources.
Entergy is advocating a reversal of the order, saying the exemptions will “become tools to artificially suppress capacity prices.”
HOLLYWOOD, Fla. — FirstEnergy and American Electric Power, both awaiting rulings from Ohio regulators on their requests for subsidies of their generation plants, may take different paths if they are unsuccessful.
The companies’ chief executives told analysts and investors at the Edison Electric Institute Financial Conference last week that they expect the Public Utilities Commission of Ohio to rule on their requests for above-market power purchase agreements with their generators late this year or early in 2016.
Akins
CEO Nick Akins indicated the company would like to rid itself of its Ohio merchant fleet, which the company acknowledged in January it had put on the block. “We’re going to be a regulated utility. That’s what we’re good at,” he said, saying that investments in generation are riskier than those in transmission and distribution.
Akins said AEP and FirstEnergy are “on the same page” regarding the need for regulators’ help to improve the finances of their Ohio fleets.
But FirstEnergy CEO Chuck Jones said his company has no plans to sell or spin off its Ohio generation fleet.
Jones
“I come from a bias that generation, transmission and distribution together is the best way to serve customers. I understand the pressures on competitive generation. I think we’ve taken steps to position ours to where we’re cash flow positive each year for the next several years — through 2018.
“I don’t see [current] prices being the right prices to sell these tremendous base load assets. So my view is we’re going to stabilize it. We’re going to keep it cash flow positive, keep it delivering positive earnings contributions.
“We’re going to work with our regulatory in Ohio to try to get 3,200 more megawatts into a safer environment for the foreseeable future … and long term we’ll see where it goes. Right now [a sale or spinoff] is not the focus.”
Chicken processor Allen Harim broke ground last week on a 1.57-MW solar installation. The 6-acre solar farm will supply about 11% of the energy used by its Harbeson processing facility.
The project, which will be connected with Delmarva Power & Light’s grid, will be owned and operated by Onyx Renewable Partners, which is owned by funds managed by Blackstone.
The installation is expected to produce 2.3 million kWh of power annually and reduce carbon emissions by 1,616 metric tons.
The Commerce Commission last week, by a 3-2 vote, approved Clean Line Energy Partners’ proposed Grain Belt Express, an HVDC transmission line that would pass through four Midwestern states.
The ICC put several conditions on its approval, including a prohibition on expanding capacity without commission approval, completion of financing and a requirement to get commission approval if any of the estimated $2 billion cost is to be borne by ratepayers.
The 780-mile line is designed to deliver Kansas wind energy into PJM. It has also received the approvals of regulators in Indiana and Kansas. Missouri regulators rejected it, but the company has vowed to reapply there.
Kevin Shepherd, a telecom industry veteran, has been named the new president and CEO of Manitoba Hydro. The Manitoba Hydro Electric Board recommended Shepherd for the position.
Shepherd rose through the ranks of MTS, the fourth-largest telecommunications company in Canada, and spent the last five years as president. He will assume the new position in December.
Baltimore Gas and Electric has applied for a rate hike for gas and electric customers to recover the cost of installing about 1.7 million smart meters. The Public Service Commission, which authorized the smart meter program in 2010, must approve the increase.
If approved, it would add about $15 per month to typical residential customers who receive both gas and electric service from the Exelon subsidiary.
“It is a very significant rate increase for our customers and our households that have combined gas and electric,” said Paula Carmody, head of the Office of the People’s Counsel. “They are asking for a profit level that’s much higher than we think is reasonable, that will likely be challenged.”
Denmark-based DONG Energy A/S is proposing a 1,000-MW offshore wind farm 15 miles south of Martha’s Vineyard, outlining its plans less than a year after the proposed Cape Wind project in Nantucket Sound suffered a stunning financial setback.
The Danish company said its Bay State Wind project would install up to 100 turbines off Cape Cod on a lease it recently acquired. DONG Energy has yet to file any applications for the projects with the federal or state government, and the transfer of the lease must be approved by the U.S. Bureau of Ocean Energy Management.
DONG Energy faces lengthy state and federal permitting processes that include environmental reviews and approvals for where its power lines would come ashore. It would take about three years to build the wind farm, and the first phase could include 30 to 35 turbines and be in service by early next decade.
State Rep. Garrett Bradley of Hingham filed a bill, which would convey the necessary easements to Tennessee Gas. Sandisfield-area lawmakers refused to file the bill because it would require the removal of protected land from the shelter of Article 97 of the state constitution, the state’s primary conservation law.
State Sen. Benjamin Downing said that the community opposes it, and passage could set a “dangerous” precedent of taking Article 97 lands to build fossil fuel energy infrastructure. He said the bill “flies in the face of the commonwealth’s energy priorities.”
Consumers Energy’s announcement that it will retire its coal-burning B.C. Cobb Plant in Muskegon brought cheers from environmentalists but could be trouble for the Port of Muskegon.
Coal deliveries accounted for about half of the tonnage coming into the port, and the volume of traffic is an important consideration if the port continues to be dredged. Without coal deliveries, the volume of cargo moved through the port will fall below the 1 million-ton annual threshold that the U.S. Army Corps of Engineers sets for “high-use” harbors, which are guaranteed to get dredged.
Muskegon city officials are setting up meetings with the corps to determine a way to keep the harbor’s dredging program active.
The Public Service Commission unanimously approved three solar projects on Nov. 10.
The plants, which will produce a combined 105 MW, will be located in Sumrall, Hattiesburg and Gulfport. They are projected to be in service for at least 25 years.
Hattiesburg Farm will cost $85 million and cover 450 acres; Mississippi Solar 2 will cost $102 million and require 4,085 acres in Sumrall; and CB Energy will spend $6.4 million on its farm at the U.S. Naval Construction Battalion Center in Gulfport.
Getting ‘Brownfield’ Solar Credits from an Apple Orchard? Nice Try
A state court upheld a decision by the Board of Public Utilities to deny brownfield development solar credits to a company that wanted to build on a former apple orchard.
Millenium Land Development said the orchard qualified as a brownfield because of past pesticide use. The BPU denied the request. The state Court of Appeals agreed, saying the land had been assessed as farmland, not a brownfield. The state’s Energy Master Plan discourages the use of open land and farms for solar development.
US Wind Inc. and RES America Developments were the high bidders to win lease rights to about 344,000 acres of ocean floor near Atlantic City to build wind farms.
US Wind bid a little more than $1 million for about 183,000 acres. RES offered $880,715 for 160,480 acres.
Together, the areas could support up to 3,400 MW of commercial wind generation, but it’s likely to take seven or eight years for operations to be developed.
State Supreme Court Denies Petition Against 4 PRC Members
The state Supreme Court last week rejected an environmental nonprofit group’s attempt to disqualify four of the five Public Regulation Commission members from voting on a high-profile case about a coal-fired power plant.
The nonprofit group New Energy Economy alleged commissioners Pat Lyons, Sandy Jones, Karen Montoya and Lynda Lovejoy have shown bias and pre-judgment in their public statements about Public Service Company of New Mexico’s plan to shut down two generating units at the San Juan Generating Station, a coal-fired power plant that PNM co-owns and operates.
State Dept. Refuses Certificate for Entergy’s Indian Point
The Department of State has refused to issue a certificate for the continued operation of Entergy’s Indian Point nuclear generating station, saying that the plant has been “damaging the coastal resources of the Hudson River” for decades by killing fish in its cooling system.
Secretary of State Cesar Perales rejected the coastal zone certificate for Indian Point, noting that the plant is close to two seismic faults and is too close to New York City. But Entergy said Perales’ rejection is moot, as it had withdrawn the application last year after a state appellate court ruled that it was not necessary. Entergy is seeking a 20-year license extension for the two reactors.
The secretary’s refusal is the latest blow against Indian Point. The state attorney general has been critical of the plant’s operation, and Gov. Andrew Cuomo has called for its closure.
Gov. Andrew Cuomo has killed a three-year-old proposal to build a liquefied natural gas terminal 19 miles off Jones Beach, citing concerns about the environment and terrorism.
The deep water Port Ambrose docking station was to supply the state with LNG from overseas. Cuomo, in formally announcing his veto, said al-Qaida has threatened to target such facilities and Superstorm Sandy was powerful enough to damage infrastructure built to survive 100-year storms. He also said the fuel port would harm commercial fishing and conflict with a major wind farm proposed for the same waters.
“When you put all of those things together, the reward was not worth the risk,” he said.
Invenergy’s proposed natural gas-fired power plant in Burrillville would lead to an even larger net decrease in regional emissions than initially forecast, the company said last week. The Chicago-based energy developer has argued that because its efficient combined-cycle plant would sell power at a lower price than competing generators, it would replace the output of older, less efficient facilities.
According to the company’s figures, the 900-MW Clear River Energy Center would reduce carbon dioxide emissions across New England 9% if it were to go online immediately. If the project starts generating power in 2019 as scheduled, the effect would be less dramatic because some of the biggest emitters, such as Somerset’s coal-fired Brayton Point Power Station, would already be closed, but the overall decrease would still be about 1%.
In a filing made with the Energy Facility Siting Board, Invenergy claims the decrease could actually be larger because of the recently announced closing of the Pilgrim Nuclear Power Station in Massachusetts.
The Public Utilities Commission has approved a 103-MW wind facility to be built near Newell. Developer Wind Quarry says the 45-turbine Willow Creek Wind Farm should be on line by December 2017.
The state ranks fourth in the nation in potential wind energy, and the Willow Creek facility would bring the state’s wind capacity to 987 MW. “Many people will be surprised to know that the addition of the Willow Creek project is likely to propel South Dakota to be the state with the greatest amount of wind as a percentage of the state’s total capacity, in the nation,” Commissioner Gary Hanson said.
Wind generation from the plains hit several all-time highs this fall, according to ERCOT and the federal Energy Information Administration. An instantaneous peak of 11,467 MW was set Sept. 13, which was broken on Oct. 21 with a new record of 11,950 MW. That record was eclipsed on Oct. 22 at 12,238 MW.
ERCOT and EIA attributed the new records to increased capacity, strong winds and increased demand due to warm autumn weather. The records were set despite lower capacity factors, estimated at between 75% and 81% during the fall compared to 83% in February.
The government predicts that with new capacity coming online, the latest record is likely to fall soon.
The excess of wind generation in the state is prompting some utilities to offer plans that don’t charge for electricity during off-peak hours, if customers agree to pay a premium during higher demand times. The New York Times recently profiled several customers who are taking advantage of a TXU Energy program that offers free overnight electricity in exchange for higher peak pricing. It said about 50 retail electricity customers are offering similar plans in the state.
Some customers said they wait to run energy-intensive appliances until after 9 p.m., when the power supply is gratis. Most wind generators in the state produce more electricity during the nighttime, when the wind blows more strongly. Wind power now represents about 10% of the state’s overall generation.
“Any plan that creates an incentive for a customer to shift a load off peak [hours] is helpful to grid operations. It’s a better use of the system,” said Paul Wattles, ERCOT senior market design analyst, told the Midland Reporter-Telegram.
Houston Signs 20-Year, $80M Solar Deal with Hecate Energy
Houston will ramp up its use of green energy to keep the lights on and laptops humming at City Hall with the approval last week of a 20-year, $80 million deal to purchase solar power from Nashville-based Hecate Energy.
Hecate, which operates 20 plants around the world, will supply the city with up to 30 MW of solar-generated power annually, beginning in December 2016, from a plant it plans to build near Alpine. Hecate offered a two-decade fixed price of 4.8 cents/kWh, nearly 2 cents less than the city pays under its current contract.
The contract will provide about 7% of the city’s annual electricity needs and will replace electricity that now is purchased from coal-fired generators.
Ector County 350-MW Gas Plant Begins Formal Operations
The Ector County Energy Center, a 350-MW natural gas plant, was formally opened earlier this month, heralded by local governmental officials as a boon to the local tax base.
The plant is designed to provide peaking energy and respond quickly when ERCOT requests additional power supply. It uses two GE 7FA simple-cycle combustion turbines fueled by Permian Basin natural gas.
Commercial operation began in September. Generation from the plant has already hit about 294 MW.
Dominion Virginia Power has requested permission to construct a 230-kV transmission line that would run above ground for 5 miles along Interstate 66 in Prince William County.
Some county officials and residents had pushed for at least part of the line to be buried.
The State Corporation Commission is expected to make a decision within 18 months.
A renewable energy developer who has challenged Connecticut’s clean energy procurement practices has taken its complaint to FERC after a federal appeals court ruled it had not exhausted all of its administrative remedies.
Allco Renewable Energy on Tuesday asked FERC to begin an enforcement action against Connecticut under the Public Utility Regulatory Policies Act. Allco says that a 2013 state law that solicited renewable energy generation and directed Connecticut utilities to enter into contracts with selected generators is an intrusion into FERC’s jurisdiction over wholesale electricity markets (EL16-11).
The company cited FERC and federal court rulings that say states have no authority to procure energy except under PURPA, which is limited to qualifying facilities (QFs) of 80 MW or less. Allco, which develops small QF solar projects, alleges Connecticut’s Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority violated PURPA by awarding a contract to a 250-MW wind farm in Maine.
Allco asked the commission to void the contract and enjoin the Connecticut agencies from entering into any other wholesale purchases except with QFs. The company also says a recent solicitation by Connecticut eliminates smaller facilities and imposes onerous fees on applicants.
Unadilla Solar Project (Source: Allco Renewable Energy)
The developer sued DEEP in late 2013 in U.S. District Court, saying it effectively crowded out smaller developments in its selection. The court ruled last year that prices were set by project bidders and the selections were not an intrusion by state regulators into the wholesale market.
Allco, which had proposed five solar projects that were not selected, appealed to the U.S. Court of Appeals for the Second District, which dismissed the complaint Nov. 6 (Case 15-20).
“Allco failed to exhaust its administrative remedies, a prerequisite for any qualified facility to bring an equitable action seeking to vindicate specific rights conferred by PURPA,” the appeals court wrote.
Allco has also filed a federal lawsuit making many of the same arguments in a challenge to a soon-to-be-released request for proposals by Connecticut, Massachusetts and Rhode Island to jointly procure renewable energy resources. (See Allco Challenges New England’s Renewable Procurement Plan.)
That lawsuit is pending in U.S. District Court in Connecticut.
Duke Energy was able to offset a slump in its international business thanks to increased revenue from its U.S. regulated operations and the early closing of certain strategic initiatives, the company said in announcing its third quarter results.
The Charlotte, N.C., company reported earnings per share of $1.35, compared with $1.80 a year ago. Adjusted earnings — excluding special items and discontinued operations — were $1.47/share compared with $1.40/share over the same period last year.
The company also narrowed and reduced its full-year guidance to $4.55 to $4.65/share from $4.55 to $4.75.
“This range reflects mild October weather as well as storm expenses, unfavorable foreign currency trends and the potential for extending bonus depreciation,” CEO and President Lynn Good said on an earnings call with analysts.
Duke’s international business has experienced a decline, contributing in 2015 about half of the $0.60/share it did in 2013 and 2014, CFO Steve Young said. “About half of this decline is due to the three-year drought in Brazil, while unfavorable exchange rates and lower crude oil prices comprise the remaining half,” he said.
Income from the international business was down to $69 million in the third quarter compared with $80 million in 2014.
Young said the division’s earnings are expected to stabilize by the end of the year and show a modest growth in 2016, when hydro dispatch is predicted to improve.
“Over the past several months, we have begun to see higher water inflows and lower market power prices,” he said. “Further, meteorologists are forecasting a strong El Nino weather pattern through early 2016, which could lead to increased rainfall in Southeastern Brazil.”
Earnings from Duke’s commercial portfolio dropped $0.08/share, primarily as a result of the sale of the Midwest Generation business to Dynegy, which closed in April. Weak wind resources this year have led the company to lower its full-year expectations from $100 million to $75 million, Young said.
However, the commercial business — unregulated renewables and commercial electric and gas transmission — is expected to get a boost next quarter from tax credits related to more than 300 MW of wind and solar generation that is set to come online.
The regulated business benefited from the recently completed acquisition of 700 MW of generation from the North Carolina Eastern Municipal Power Agency. The business also was boosted by the first warmer-than-normal summer since 2012 in the Carolinas.
“On the regulated side, we’re on track to complete construction of 128 MW of utility-scale solar in North Carolina by the end of this year, and are moving forward with investments in both South Carolina and Florida,” Good said.
Young said Duke Energy also has been successful in attracting new business that is expected to add nearly 7,200 jobs in its six-state service area.
Duke Energy, which earlier this year was hit with $102 million in federal penalties related to the massive Dan River coal ash spill, made its final payments last week with two $5 million contributions to environmental remediation programs.
The money went to a Texas-based firm, Resource Environmental Solutions, to fund remediation in Virginia and the Carolinas.
The payments settle Duke’s guilty pleas to nine misdemeanor violations of the federal Clean Water Act. The pleas came as a grand jury was considering criminal charges against the company relating to its handling of coal ash at 14 North Carolina plants. Duke agreed to pay $68 million in fines and $34 million in restitution.
Xcel Energy is proposing the option of 100% renewable electricity for its Minnesota customers. The “Renewable Connect” program would be offered to all customers, but it is primarily aimed at business and corporate customers seeking to achieve sustainability goals.
The plan, submitted to the state Public Utilities Commission, would offer a package of wind and solar energy at a premium price, but Xcel said it would not take a profit from it. The company said the plan would provide long-term pricing certainty and allow customers to claim environmental awareness, something many companies value.
“Businesses are more careful about how they source everything, including energy,” said Bill Blazar, a vice president of the Minnesota Chamber of Commerce. “It is almost like a kosher seal on a chicken — they are looking for that something to offer to their customers who want it. They are responding to the market.”
The Marysville Power Plant, a coal-fired generator that stood for 93 years in eastern Michigan on the banks of the St. Clair River, was demolished in a controlled implosion on Nov. 7.
In its heyday, the plant employed about 250 people and produced 1,386 MW. Operations ceased in 2001. Owner DTE Energy sold the 30-acre site to a developer, who plans to convert the waterfront property into a multi-use facility including retail shops, housing, a marina and bike trails.
DTE Energy announced plans Nov. 6 to partner with southeastern Michigan’s Port of Monroe to market and transport gypsum produced from the emissions-control system at its Monroe Power Plant.
Under the collaboration, gypsum will be shipped from the Lake Erie port to clients in Canada and the Midwest. The Port of Monroe says it will build a 24,000-square-foot storage building. DTE, which recycled more than 350,000 tons of gypsum last year, said the arrangement will enable the utility to recycle 100% of its gypsum going forward.
Synthetic gypsum is produced from flue gas desulfurization systems, or “scrubbers,” which use lime or limestone as reagents. The byproduct is nearly identical to mined gypsum and can be used in manufacturing cement and drywall.
TXU Solar Partnership Offers High-Efficiency Home Panels
Texas retailer TXU Energy last week introduced a program it calls “TXU Solar from SunPower,” providing high-efficiency solar panels that the manufacturer says produce 70% more energy than conventional panels.
The program comes with a simple online and mobile monitoring system so homeowners can track their electricity production. SunPower said its panels, which have an expected lifespan of 40 years, will enable residential consumers to produce more of their own electricity than competing rooftop systems.
The new offer is being launched in North Texas. To be eligible, consumers must own a single-family home with a south-to-southwestern exposure.
Basin Electric: SPP Membership Helps Prepare Co-op for Future
Basin Electric Power Cooperative CEO Paul Sukut says joining SPP last month has expanded the North Dakota co-op’s access to power.
Sukut, speaking during Basin’s annual meeting earlier this month in Bismarck, said the cooperative’s membership in the regional grid allows it to purchase more power to supply growing demand. He said Basin is trying to keep up with the market while still maintaining its cooperative values.
“I can’t recall a time in the last 30 years we have had this much at stake,” he said, alluding to the Environmental Protection Agency’s Clean Power Plan.
American Electric Power has closed the sale of its commercial barge operation to American Commercial Lines for $550 million. AEP bought the river operation in 2001, but the company decided earlier this year to divest the asset and redeploy the capital to its regulated operations. The sale netted about $400 million after taxes, debt retirement and fees.
AEP will retain ownership of a fleet of 12 tow boats and 429 barges to deliver coal to its coal-fired power plants, but ACL will dispatch and operate the fleet through 2016. AEP River Operations, now the property of ACL, has its own fleet of about 56 towboats and 2,300 barges that deliver 45 million tons of commodities on inland waterways, including 10 million tons of coal.
Unit 1 at Talen Energy’s Susquehanna nuclear power plant automatically shut down Thursday after a malfunction that is being investigated.
Talen Energy assumed control and partial ownership of the plant earlier this year when it was spun off from PPL. Allegheny Electric Cooperative also owns a share of the plant.
Talen said the unit’s safety features worked as designed and that there was no release of radiation. Unit 2 remained in operation, according to the company.
FERC last week denied requests by Texas and Louisiana regulators for rehearing of its December 2013 order approving the Entergy operating companies’ incorporation into MISO and Entergy Arkansas’ exit from the companies’ system agreement.
The Public Utilities Commission of Texas contended FERC was wrong because in filing “limited” amendments to the agreement, Entergy didn’t subject its entire system agreement to scrutiny.
The Louisiana Public Service Commission contended that FERC’s order failed to determine what entity is responsible for costs left when an operating company withdraws. It said ratepayers of the last remaining company in the operating company system could unjustly bear the brunt of the costs needed to plan and operate the resources of multiple companies. Louisiana regulators also questioned whether Entergy’s proposed congestion cost would correspond with MISO practices and suggested that Entergy Arkansas’ exit would leave a regulatory gap in state authority over Entergy.
FERC’s Nov. 9 order denied the commissions’ complaints on all fronts, saying that the system agreement doesn’t require withdrawing companies to pay an exit fee or otherwise compensate remaining companies (ER13-432-001).
“[Entergy Arkansas’] integration into MISO does not require a broader review of the system agreement. Nothing about Entergy’s intent to operate as a power pool within MISO is inherently inconsistent with behavior in an organized market,” FERC wrote. “Furthermore, nothing in the system agreement or commission precedent would bar Entergy from integrating the operating companies into MISO as a power pool.”
FERC last week also accepted Entergy’s compliance filings required by the 2013 order (ER14-1263, et al). The commission had ordered the companies to amend their costs and credits allocator to use energy usage instead of peak demand as the basis for calculations.
The Louisiana commission protested that Entergy’s revised allocator “departs dramatically from the criteria articulated by the commission” by using monthly energy usage data instead of hourly energy usage data, as MISO’s Tariff states. They asked FERC to reject Entergy’s method on the basis that it violated cost-causation principles.
FERC instead accepted Entergy’s compliance filing, noting that using hourly energy usage data “would be problematic because it would be inconsistent with the monthly allocation of ancillary services and uplift charges and credits related to generating units.”
“We find that Entergy has provided sufficient detail in its compliance filing to explain how it will calculate the energy-based allocator and has justified why its proposal is just and reasonable,” the commission wrote.
FERC Commissioner Colette Honorable, a former Arkansas regulator, did not participate in either ruling.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following manual changes:
Manual 01: Control Center and Data Exchange Requirements. Adds requirements and changes terminology to be consistent with North American Electric Reliability Corp. standards. Makes minor edits for clarity. Removes dated reference to “floppy disk.”
Manual 03: Transmission Operations. Changes resulting from bi-annual review include project updates, edits and reorganization of sections.
Manual 12: Balancing Operations. Updates due to new instantaneous reserve check implementation. Eliminates mention of MISO as the Interconnection Time Monitor.
Manual 13: Emergency Operations. Updates day-ahead scheduling reserve requirement for Reliability First Corp. effective Jan. 1. Other changes made for consistency. Removes requirement that generators connected below 230 kV participate in voltage reduction.
Revisions to Manual 19: Load Forecasting and Analysis reflect updates to the PJM load forecast model. Adds variables to account for trends in equipment and appliance saturation and energy efficiency; revises weather variables; updates weather station assignment to zones; and revises weather normalization procedure. PJM will be publishing a white paper in 2016 to provide more detail on the forecast model. (See “Manual Changes on Load Forecast Approved Except for Solar Revision” in PJM Planning Committee and TEAC Briefs.)
Revisions to Manual 18: PJM Capacity Market and Manual 18B: Energy Efficiency Measurement & Verification to accommodate energy efficiency resources in the capacity market when they are reflected in the peak load forecast.
The committee will be asked to endorse modifications, clarifications and revisions to 12 terms in PJM governing documents.
xx. UNDERPERFORMANCE RISK MANAGEMENT IN RPM/CP (10:25-10:40)
Bob O’Connell, on behalf of the Supplier Caucus, will present a proposed problem statement and issue charge related to underperformance risk management in the capacity market. It would expand ways for generators to minimize penalties by netting them against over-performing generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)
Members Committee
ENDORSEMENTS (1:25-2:05)
1. 2015 IRM STUDY RESULTS (1:25-1:40)
Members will be asked to endorse the installed reserve margin study results, re-setting IRM and the forecast pool requirement for 2016/17, 2017/18 and 2018/19 and establishing initial IRM for 2019/20. The study increases the IRM to 16.4% from 15.5% in the 2014 study. The IRMs also rose for the following two delivery years. (See “Committee Endorses Increase in IRM” in PJM Markets and Reliability & Members Committees Briefs.)
2. 2016/17 THIRD INCREMENTAL AUCTION (1:40-1:55)
As part of the transition to Capacity Performance, the committee will be asked to approve Tariff revisions allowing PJM to sell excess base capacity acquired in the third Incremental Auction for 2016/17 in February. (See “Tariff Change Would Allow PJM to Sell Excess Capacity for 2016/17” in PJM Markets and Reliability & Members Committees Briefs.)
3. ELECTIONS (1:55-2:05)
Members will be asked endorse the following elections:
Finance Committee
End Use Customer, David Evrard, Pennsylvania Office of the Consumer Advocate
Generation Owner, Michelle Greening, Talen Energy
Other Supplier, Marguerite Miller, Credit Suisse
Transmission Owner, Jim Benchek, FirstEnergy
Sector Whips
Electric Distribution, Steve Lieberman, Old Dominion Electric Cooperative
End Use Customer, Susan Bruce, PJM Industrial Customer Coalition
Generation Owner, Joe Kerecman, Calpine
Other Supplier, Katie Guerry, EnerNOC
Transmission Owner, Jodi Moskowitz, Public Service Enterprise Group
WASHINGTON — PJM transmission owners defended their jurisdiction over maintenance of the grid last week under questioning by FERC staff at a technical conference held to gain insight into the RTO’s local planning process.
Commission staff questioned PJM officials for almost four hours on subjects ranging from the difference between its Planning Committee and Transmission Expansion Advisory Committee to what is discussed at its sub-regional committee meetings.
Zeny Magos, FERC asking a question.
The staffers were particularly interested in learning how PJM reclassifies supplemental projects as baseline projects in its Regional Transmission Expansion Plan and how it determines whether local transmission needs should be opened to competitive proposals under Order 1000.
FERC ordered the conference in September, partially in response to a complaint by Dayton Power & Light over the reclassification of the Cunningham-Elmont 500-kV end-of-life project in Virginia as a baseline project in the 2015 RTEP. Dominion Resources originally proposed the rebuild as a supplemental project, meaning it would bear the full costs. (See FERC Sets Tech Conference on PJM Tx Planning Rules.)
In June, FERC issued a deficiency letter seeking additional information on PJM’s cost allocations for 61 baseline upgrades, including the Cunningham project. In its response, PJM acknowledged that “there is no specific language in either [the Tariff] or the PJM manuals that explains how PJM re-categorizes a supplemental project to a required transmission enhancement eligible for regional cost allocation.”
Supplemental Projects
PJM Vice President of Planning Steve Herling, who did most of the talking for PJM at the hearing, told FERC that supplemental projects are proposed at the discretion of the TOs and are not in response to any violations of North American Electric Reliability Corp. standards or the TO’s own planning criteria. They’re often proposed to replace aging infrastructure. “If you went down the list in our database, I guess half of them start with the word ‘replace,’” he said.
Supplementals “could very well mask a violation that would have otherwise arisen, and it will not be obvious to anyone that such a violation would have arisen,” Herling said. This only becomes apparent if the TO decides not to go forward with the project and, once pulled from the RTEP, PJM finds that a violation would occur. The project would then be converted to a baseline project.
Valerie Teeter, of FERC’s Office of Energy Policy and Innovation, asked PJM what that conversion process entails: “Does that violation kind of go back to the beginning of the stakeholder process? [Does it] go through the process that any other violation would? Is there a proposal window for solutions?”
“It’s all a matter of timing,” Herling responded. If the supplemental was identified three years ago and PJM realizes that absent the supplemental there will be a violation, construction on the project is likely to have begun. “At that point, we’re certainly not going to shut the project down so that we can hold a [proposal] window and see if a better project exists,” he said.
But, Herling said, that decision is “purely judgmental,” meaning there’s no bright line for when the RTO would open a proposal window to select the most cost-effective solution.
“Where it gets gray is in the middle,” when PJM notices a potential violation a year after a supplemental is proposed, for example. “Depending on the circumstances, we would likely say, ‘OK, put the brakes on, we’re going to open up a window’” for competitive proposals, Herling said. “Again, it’s very judgmental. It’s all going to be case-by-case based on the circumstances.”
Cunningham-Elmont
PJM reclassified the Cunningham line after Dominion revised its planning criteria last year. In its complaint, DP&L accused Dominion of exploiting what it called a loophole resulting from an Order 1000-related filing by PJM TOs that permits a portion of the costs of new 500-kV baseline projects to be shared by load-serving entities throughout the RTO.
Herling said that any party, including PJM, can identify whether a project might need to be converted from supplemental to baseline, especially in the case of aging infrastructure. However, “most often, my gut is it will be the transmission owner who will recognize the likelihood that the project should be converted. It is not always intuitive to anyone else.”
For the Cunningham rebuild, Dominion provided a “condition assessment” that the company said justified converting the project to baseline. Performing a condition assessment “is not the kind of thing that PJM could take as an initial step on their own,” Herling said. PJM then did its own evaluation based on Dominion’s work to confirm that it met the criteria for a baseline.
FERC staff asked why a proposal window was not opened for the need associated with Dominion’s planning criteria for aging infrastructure.
“That’s one we’re continuing to think our way through as a general matter,” Herling replied. “It’s challenging to us to justify going out and seeking other proposals when you’re going to have to tear the line down anyway, [and] the state would prefer you reuse the existing right of way.” In Cunningham’s case, PJM determined a violation would occur if it was taken out of the RTEP, so it needed to be replaced.
Hertzel Shamash, vice president of resource planning for DP&L, spoke up at this. “You [eliminate] any of the existing transmission lines … and you’re going to violate NERC standards, because you need that line. It wouldn’t be there if you didn’t need it.
“Regarding the open window: Yeah, you can build on existing rights of way, but someone can build it for a lower cost,” he said.
Maintenance, not Planning?
TO representatives pushed back at staff’s focus on the lack of a defined conversion process. The Cunningham case, in which a change in planning criteria led to a conversion, “is relatively rare,” said Steve Naumann, vice president of transmission and NERC policy for Exelon. “It’s a unique circumstance.”
Steve Naumann, Exelon responding to a question
“The drivers [of supplemental projects] can be so different, and many of them are management of the assets, which is not something that has been turned over to PJM,” Naumann said. “That has remained with the transmission owner: to manage their own assets, as opposed to transmission expansion. The TOs as a whole believe there’s no need — nor is there a requirement — to have a … hard and fast set of filed criteria for supplemental projects. Otherwise they wouldn’t be supplemental projects.”
Maintenance of the system is solely the purview of the TOs, said Frank “Chip” Richardson, manager of transmission regulatory and business affairs for PPL. “It’s excluded from PJM’s processes… You don’t see any processes where PJM evaluates the maintenance of the system.”
“We, by definition, don’t think supplemental projects are planning projects,” said Raja Sundararajan, vice president of transmission asset strategy and policy for American Electric Power. When AEP finds things that are broken and need to be fixed, it lets PJM know, he said. “Is that a planning process? No, that is not a planning process. That is fundamentally a maintenance and replacement of the assets.”
Maintenance is a business decision left solely up to the TO. “There’s a clear delineation of where planning is and when operation begins,” Sundararajan said.
FERC Unconvinced
FERC staff seemed unconvinced by these arguments. “I am not seeing that delineation,” replied Zeny Magos of FERC’s Office of Energy Markets and Reliability. “I personally do not see the difference between planning your transmission system and maintaining your transmission system.”
Mark Ringhausen, vice president of engineering for Old Dominion Electric Cooperative, also had complaints about the lack of process. He said one of ODEC’s neighboring TOs presented $250 million in supplemental projects last year, including rebuilds for aging infrastructure. He said PJM told ODEC the co-op didn’t have the ability to influence changes to other TOs’ supplemental projects because PJM said such projects are outside the RTO’s jurisdiction. “Clearly there is no process,” Ringhausen said.
Ringhausen cited FERC’s June 22 rehearing order on the planning and cost allocation requirements of Order 1000. In it, the commission said it read the PJM Operating Agreement as giving stakeholders “an opportunity at the early stages of each individual PJM transmission owner’s planning of supplemental projects (i.e., before each transmission owner actually identifies any potential supplemental project) to review the criteria, assumptions and models each individual transmission owner uses to plan supplemental projects” (ER13-198).
“Is that happening today?” Ringhausen asked. “Clearly … it’s not happening at the early stages.”
“RTEP is the Regional Transmission Expansion Plan,” Richardson countered. “It’s not the ‘Regional Transmission Maintenance Plan.’ There’s never been anything in PJM about how the transmission owners maintain their equipment.
“The definition of ‘supplemental’ is PJM does not need it,” he said. “They would never tell us to do it.”
Going Forward
Magos asked PJM if it thought it needed to update its Tariff or manuals to include a conversion process.
“My gut is we would probably want to take a look at updating the PJM manuals, which probably could be made to point to any number of existing practices that are in the Tariff, just to ensure they are applicable also,” Herling said. “Now if in the commission’s judgment that needs to be in the Operating Agreement or the Tariff, fine, we can certainly do that. But we would do the manuals first.”
“It would be very helpful, I think, for some of the people who have to pay for these projects to have a bright line in the Tariff that explains how you go from supplemental to regional transmission planning,” said Amy Fisher of Linden VFT. “That would be kind of an exclamation point that people should be very engaged in that process.”
FERC staff requested comments be filed by Dec. 10 on several issues discussed at the conference, including the process for reclassifying supplementals, stakeholder input on supplemental projects and the difference between transmission planning and transmission maintenance.
