Connecticut Light & Power’s proposed distribution rate increase was cut by 41% by the state’s Public Utilities Regulatory Authority in a draft decision.
The utility asked for $221 million in additional revenue with a 10.2% return on equity (ROE). The draft ruling would allow recovery of $130.1 million, including some previously approved costs from major storms in 2011 and 2012. The ROE was cut to 9.17%. The base ROE was further cut to 9.02% for one year as a penalty for the utility’s performance in preparation and service restoration from Tropical Storm Irene in 2011 and an October 2011 snowstorm.
CL&P also proposed increasing the monthly service charge that most residential customers must pay regardless of consumption to $25.50 from the current $16. The draft decision allows the fixed rate to increase to $19.50 monthly.
An average residential customer using 700 kWh of electricity would see an increase of approximately $7.12 per month. PURA said the increases will be sufficient to allow CL&P to fund capital improvements to upgrade its distribution system.
A final vote by PURA’s commissioners is scheduled for Dec. 17.
NextEra Energy, parent company of Florida Power & Light, announced plans to buy Hawaiian Electric for $2.63 billion, taking over a utility that is losing significant load to renewable competition.
NextEra, already North America’s largest generator of wind and solar electricity, was interested in Hawaiian Electric because of the utility’s ambitious plans to wean itself from fossil fuels. Hawaiian Electric has said it plans to get 65% of its power from renewable sources by 2030.
“It makes a lot of sense for NextEra with all the renewables that Hawaiian Electric was going to do,” Tim Winter, an analyst at Gabelli & Co. in Rye, N.Y., told Bloomberg News. NextEra is “the premier renewable energy builder and developer and really good at transmission.”
Wisconsin Public Service Corp. to Build 400-MW Plant near Kaukauna
Green Bay-based utility Wisconsin Public Service Corp. plans to build a 400-MW natural gas-fired plant at its Fox Energy Center.
In filings with the state Public Service Commission, WPSC said the new generation could offset contemplated retirements of coal-fired plants. The $500 million project would get underway in the spring of 2016 and be operational by 2019.
The Fox Energy Center in Kaukauna is home to two plants, generating 600 MW. WPSC is a subsidiary of Integrys, which is being acquired by WE Energies of Milwaukee in a $9.1 billion deal.
Ameren’s Callaway Plant Offline After Reactor Trips Because of Unknown Issue
Ameren Missouri’s 1,200-MW Callaway nuclear generating plant shut down last week after an electrical problem caused its reactor to trip, forcing the utility to use other plants to make up for what amounts to about 20% of its electricity supply. The Nuclear Regulatory Commission, after a preliminary investigation, classified the incident as a nonemergency and said no radiation was released.
The reactor trip came not long after crews finished refueling the reactor and installing a new reactor vessel pressure head, but company officials said the outage was unrelated to those jobs. They did not say when the plant will be restarted.
Ameren Welcomes its First Solar Facility in its 100-Year History
Ameren Missouri, which has been in business for more than a century, launched its first solar energy facility last week.
The 6-MW O’Fallon Renewable Energy Center is the first solar facility in Ameren’s mix, company officials said. A second plant is to be built in 2016.
“We are moving away more from carbon-based energy and this solar plant is one of the strategies Ameren Missouri is executing on,” said Scott Wibbenmeyer, the company’s manager of renewable development.
Xcel Denies it Owes Babcock & Wilcox $45M for Steam Generator Work
Xcel Energy, answering an allegation from Babcock & Wilcox Nuclear Energy that it owes the contractor $45 million for work done at the Prairie Island Nuclear Power Plant in Red Wing, Minn., said they both share responsibility for the project’s cost overruns and delays.
B&W “continued to lose ground against the schedule on a virtually daily basis,” Xcel said in court filings. In fact, Xcel said, the contractor owes it $3 million.
B&W said the increased costs of the job came about in part because Xcel changed the scope of the work. The work at the plant took more than a year.
PSE&G, Pilgrim Still Negotiating over Right-of-Way for Pipeline
Officials of Pilgrim Pipeline Holdings and Public Service Electric & Gas say they are still in negotiations over access to the utility’s land in New Jersey for use of a controversial pipeline, despite news reports that PSE&G had denied Pilgrim access.
The state chapter of the Sierra Club, which is opposed to Pilgrim’s plan for the pipeline, posted a news release on its website that said Pilgrim “was denied access to PSE&G right-of-way by the PSE&G Corporate Lands Division and now senior leadership has upheld that decision.” But Pilgrim official George Bochis said the companies are still talking. “It is early in the process and we continue to have discussions with PSE&G,” he said.
The 178-mile pipeline would transport crude oil from a rail terminal in Albany, N.Y., to a refinery in Linden, N.J. It would then carry refined products from Linden northward.
Dominion’s Millstone Nuclear Plant to Stay Non-Union After Vote
Workers at Dominion Resources’ Millstone Power Station in Waterford, Conn., last week rejected a measure to join the International Brotherhood of Electrical Workers. The vote was 183 for unionization to 222 against.
IBEW officials claimed that Dominion allowed some employees to take part in the election who shouldn’t have been eligible, including supervisors. “The company spent a tremendous amount of money to get the results to go their way,” said John Fernandes, business manager for IBEW Local 457.
A Millstone spokesman said the company was pleased with the results.
ISO-NE generators asked federal regulators to change market rules ahead of February’s capacity auction while state officials complained consumers face excessive costs because of unrealistic load forecasts. In all, the ISO’s load and supply interests opened three capacity market dockets at the Federal Energy Regulatory Commission in the last two weeks. (See related story, States, NEPOOL: ISO-NE Overestimating Capacity Needs.)
By William Opalka
Exelon, Calpine: ISO-NE New Entry Rule Suppresses Prices
Exelon and Calpine want FERC to change a pricing rule in the forward capacity market (FCM) in New England that FERC has previously rejected in PJM.
The companies are seeking a ruling by Jan. 23, before ISO-NE’s Forward Capacity Auction (FCA) for the 2018/19 capacity commitment period begins Feb. 2.
The New Entry Pricing Rule in the ISO-NE Tariff gives the sponsor of a new resource the option of locking in the price at which the resource first clears in an FCA for up to six subsequent delivery years.
In a complaint filed Nov. 28 (EL15-23), the companies said the rule suppresses prices for other capacity providers because it results in new resources entering the equivalent of zero-price offers in the six additional years.
FERC had rejected a similar rule in PJM but noted that PJM uses a downward-sloped demand curve in its capacity market.
“That distinction is no longer valid as ISO-NE has adopted a downward-sloping demand curve beginning with the FCA for the 2018/2019 capacity commitment period,” the companies said. “As a result, the PJM precedent is now indisputably applicable to ISO-NE’s FCM rules.”
They said they are not trying to eliminate the rule but asked the commission to “remedy the impacts of the resulting price suppression.” Such a remedy could “entail additional payments” to other capacity suppliers, they said.
The New Entry Pricing Rule was intended to provide predictable revenues for new capacity. Earlier this year, the maximum lock-in period was extended from five to seven years, which FERC had acknowledged could result in lower market clearing prices.
The companies supported their complaint with an affidavit from Michael M. Schnitzer, a director of the NorthBridge Group, who said the zero-price offer requirement will significantly suppress FCM clearing prices, hurting both existing resources and new ones.
“Remedying this price suppression is even more vital in this case than it was in PJM’s case, because locked-in pricing is more widely available and the potential lock-in period is more than twice as long under ISO-NE’s New Entry Pricing Rule than under PJM’s [New Entry Price Adjustment] mechanism,” the companies added.
New England Gens: Cut Rebate Payments
Meanwhile, the New England Power Generators Association wants ISO-NE to immediately roll back the Peak Energy Rent Adjustment, saying recent policy changes eliminate the need for it and that its existence threatens reliability.
The group representing the owners of 26,000 MW of generation in New England filed a complaint (EL15-25) with FERC on Dec. 3. They seek to have ISO-NE modify the PER for Capacity Commitment Periods 5 through 8 — from now until early 2018 — and then eliminate it altogether for FCA 9. The auction covers delivery year 2018/19, when the ISO will implement its pay-for-performance program, which will tie capacity revenues to real-time performance.
“The current PER Adjustment, which obligates capacity suppliers to rebate a portion of their capacity revenues based on real-time energy prices, is unjust and unreasonable in light of the increases in the Reserve Constraint Penalty Factors (RCPFs) in ISO-NE’s energy market directed by the commission earlier this year,” the association said.
NEPGA requests a refund-effective date of Dec. 3, the effective date of the previously accepted increase in the RCPFs.
The new RCPFs could substantially increase real-time energy prices and, by extension, the PER Adjustment.
NEPGA says the PER Strike Price, which determines the magnitude of the PER Adjustment, should be increased by $250/MWh, as proposed recently by ISO-NE in its stakeholder process in response to the change in RCPFs.
The proposal fell short of the 60% support ISO-NE said it would require to seek FERC approval. The proposal won almost 58% support at the Markets Committee and a 47% vote in favor at the New England Power Pool Participants Committee.
The PER Adjustment was designed in part to discourage the exercise of market power through withholding and to provide a hedge to load against high real-time prices. NEPGA says any benefits now are outweighed by its likely cost.
The Federal Energy Regulatory Commission approved a revised joint operating agreement (JOA) between PJM and Duke Energy Progress (DEP) last week despite protests from the RTO’s Independent Market Monitor that it gives Duke favored treatment on interchange pricing.
The revisions to the JOA, which PJM originally signed with Progress Energy Carolinas (PEC) in 2005, were relatively minor, including updates to the company’s name and contact information to reflect Duke Energy’s 2012 acquisition of the utility.
The Market Monitor filed a protest in October contending that PJM should terminate the JOA and negotiate a new one to reflect the joint dispatch agreement (JDA) that PEC and Duke Energy Carolinas signed as part of the acquisition. (See IMM Calls for New PJM-Duke Progress JOA.)
FERC dismissed (ER15-29) the Monitor’s protest, saying that it was challenging unchanged portions of the agreement, not the changes themselves, making the protest beyond the scope of the filing. The commission said the Monitor could file a complaint in a new docket making its case that the dispatch agreement renders the JOA unjust and unreasonable.
In joint comments filed last month, PJM and DEP called the Monitor’s protest “a pretext to rehash old arguments on which the commission has already ruled.”
“Having failed to obtain its desired result in 2010 [when FERC approved the JOA], the PJM IMM now tries for a second bite at the apple,” they said.
Electric demand, industrial use and liquefied natural gas exports will make the Southeast the top destination for natural gas in the U.S. by 2019, according to a Bentek Energy study for America’s Natural Gas Alliance (ANGA).
Richard Smead, managing director of RBN Energy, presented the study results at a meeting of MISO’s Entergy Regional State Committee in Austin, Texas, last week.
Demand in the 10-state Southeast region will increase by 9.5 Bcf/d by 2024, about 39% of the projected demand growth in the U.S.
Gas burned to produce power will increase by 2.2 Bcf/d in the region, a 31% jump, with triple-digit increases in Tennessee (+290%), Kentucky (+276%) Arkansas (+150%).
“The rate of growth in power generation has been huge. A lot of that is driven of course by coal retirements … which raises the question of whether gas is capable of doing this,” Smead said. The answer, he said, is yes.
The study concludes that there is enough supply and pipeline capacity to meet any plausible power generation demand scenario in the Southeast “with stable, affordable power,” Smead said.
LNG Exports
Combined with LNG exports and increased industrial demand, the Southeast will become the nation’s top demand region by 2019, surpassing the Northeast. LNG exports will be responsible for more than half of the Southeast’s demand growth, with LNG shipments from three terminals in the Gulf and one in Georgia projected to hit 5.7 Bcf/d by 2021.
The Northeast is projected for a 3.4 Bcf/d increase in demand by 2024, less than a quarter of its projected 15.1 Bcf/d increase in production.
The Southeast’s demand growth will exceed its projected 3.1 Bcf/d increase in production, but its existing pipeline infrastructure — originally built to carry gas from the Gulf of Mexico to other regions — and pipeline projects capable of carrying 13 Bcf/d should be able to handle the imports. The region currently imports more than 5 Bcf/d.
There are 200 major industrial projects proposed for the Southeast, including a methanol plant envisioned for Louisiana. That guarantees that the pipelines will get built, Smead said. “It’s not being left to the [electric] utilities to pay for it all.”
Break-Even Prices Down
Meanwhile, producer break-even prices have fallen below the levels assumed in the Bentek study, which projects North American production growth of 26 Bcf/d by 2024.
“We’re running into studies now that are indicating between big increases in efficiency and the gas coming forward with oil production … that producer break-even prices are really closer to $2.50 to $3 [per MMBtu], meaning production growth just keeps on going,” Smead said.
PJM began voluntary winter testing of infrequently used generators last week, one of the RTO’s efforts to avoid the high level of forced outages last January.
“We had some units fail to start,” PJM’s Dave Schweitzer said. “That justifies this testing.”
The testing is open to units that have not run in the prior eight weeks, including dual-fuel units that have run only on their primary fuel during that time.
Some units that were initially nominated to participate were eliminated when they were called on to produce energy during November’s cold snap, Schweitzer said.
In a related matter, PJM said it expects to allow generators to begin testing in January on software revisions allowing them to update fuel costs intraday and to enter data on dual-fuel capabilities and operational restrictions.
Synchronized Reserve Performance Up with Increased Penalties
Tier 2 synchronized reserve resources have shown a big improvement in performance since PJM initiated tougher non-performance penalties in January.
Demand-side resources have provided 86% of assigned megawatts during synchronized-reserve events that lasted more than 10 minutes so far in 2014, up from 62% in 2013.
Generation resources showed an even bigger year-over-year improvement, to 89% in 2014 from 59% in 2013.
Since 2007, generation resources had achieved 80% or better performance only twice before. The connection between performance and the increased penalties is less clear for demand resources, which hit 85% in 2011 and 100% in 2012.
Both resource types also showed big year-over-year improvements for events lasting less than 10 minutes. For all events, demand resources provided 74% of assignments, up from 63% in 2013.
Generator performance rose to 77% from 55%, with combined-cycle units more than tripling their performance from 49% to 163%, once again the best among all generation types. Combined-cycle units’ performance had fallen by half between 2008 and 2013. (See CC’s Synchronized Reserve Performance Drops.)
PJM increased non-performance penalties effective Jan. 1 after determining that the previous rules — written when SR calls occurred about every three days — had lost their effectiveness as the calls became less frequent.
The Gates brothers have returned to their battle stations.
In October, hedge fund twins Rich and Kevin Gates stopped talking to the press and pulled down a website detailing their battle against the Federal Energy Regulatory Commission Office of Enforcement — a sign many saw as an indication that they were seeking a settlement over FERC market manipulation allegations.
Yesterday, the site was back up again. The decision to reactivate the site was spurred, according to Kevin Gates, by a Dec. 5 notice that FERC is about to move on to the next step — civil prosecution.
“We were hoping to move on with our lives and focus on other matters” when they decided to deactivate their website in October, Gates said Monday. “Then we got this letter, which seems to suggest that FERC would not let us move on.”
Gates steadfastly denied that any settlement with FERC was ever in the works. “There were never any settlement discussions,” he said. “We were just tired, and wanted to get on with our lives.”
The letter from FERC attorney Steven C. Tabackman indicated that the agency would make a public release about the investigation sometime after Dec. 10.
Gates is convinced it is going to be an order to show cause.
An order to show cause is the probable next step in the enforcement process, announcing a formal proceeding against the subject of an investigation, according to the FERC website explaining its enforcement process.
In August, the day after Bay was sworn in as commissioner, FERC staff issued a notice of alleged violations accusing the brothers and their partners in Powhatan Energy Fund of engaging in “manipulative” up-to-congestion trades in PJM in 2010. (See PJM UTC Case Likely Headed to Court After FERC Notice.)
At the time, Kevin Gates vowed to fight on.
On Oct. 21, FERC issued a notice that Commissioner Norman Bay was recusing himself from the Powhatan case. Bay headed up the FERC enforcement office when the investigation started. Shortly after that notice was published, the Gates brothers took down their site.
PJM is reducing its load forecast for 2018 by 2.6%, due in part to a temporary change in modeling that aims to address over-forecasting in recent years.
Acknowledging criticism that its forecasts have overestimated economic growth and failed to capture energy efficiency and behavioral changes that have dampened demand, PJM officials will use a “binary variable” to reduce next year’s forecast.
“There are things outside our model that our model is not picking up,” PJM’s Andrew Gledhill told the Planning Committee last week in a briefing on its draft load forecast.
Before applying the variable, PJM was projecting a 1.5% reduction in its 2018 summer peak load compared with the projection it made last year.
In addition to reducing the forecast for summer 2018 — the delivery year for next year’s capacity auction — the draft report reduces the summer peak load forecast for 2015 by 4,716 MW (-2.9%).
Peak load for 2020, the next Regional Transmission Expansion Plan (RTEP) study year, was cut by 4,152 MW (-2.5%) versus last year’s projection.
Economist James Wilson, a consultant to consumer advocates, questioned the use of the binary variable, saying it overcorrects in the short term and results in too high a rate of growth in later years. “It’s not a very good approach,” he said.
PJM Vice President of Planning Steve Herling said the debate would soon be moot. “I’m less concerned about the long-term implications of [this year’s fix] because we’re not going to be doing it next year,” he said.
Wilson also questioned why forecasters continue to add years to their historical period instead of dropping some of the earlier years.
Wilson said the first four years of PJM’s 1998-2014 historical base was a period when peak demand was growing in about a 1-to-1 relationship with growth in PJM’s economic variable, an elasticity that hasn’t been seen since and which may not return because of increased energy efficiency and demand response.
“A better way to move the forecast in the right direction would be to drop some of those now-anomalous early years from the forecast period,” he said.
Gledhill said the data from those previous years remains valid. “When you start shortening the estimation period, you’re shortening the period where you can measure how load reacts to economics,” he said.
Direct Energy’s David “Scarp” Scarpignato backed Wilson’s argument. “Something’s changed that’s making that data way-back-when less useful in the forecast,” he said. “Do you really want more data points if some of the data points are garbage?”
Herling said a final forecast report will be presented by the end of this month.
The electric and natural gas industries remain divided over the start of the gas day, nine months after federal regulators proposed changing the start time from 9 a.m. CT to 4 a.m. CT.
On March 20, the Federal Energy Regulatory Commission issued a Notice of Proposed Rulemaking proposing the change to better align it with electric operations (RM14-2). The commission gave the North American Energy Standards Board six months to reach consensus among its gas and electric industry stakeholders. (See FERC: Six Months to Move Gas, Electric Schedules.)
But NAESB reported in September that the two sectors remained split, with the gas industry resisting any change in the start time. When the comment period on the NOPR closed at the end of November, there was no evidence of any change in the stalemate.
Thus it will be up to FERC to decide whether to change the start time over the gas industry’s objections.
Whether Chairman Cheryl LaFleur has the votes to force a change is unclear. The commission approved the NOPR on a 3-1 vote with LaFleur, Commissioner Philip Moeller and former Commissioner John Norris in support. Commissioner Tony Clark dissented, saying he wanted to give the industries more time to reach consensus before FERC “put its thumb on the scale” in favor of a change.
In their comments, stakeholders from both industries were largely supportive of other modifications proposed by NAESB.
Besides changing the start of the gas day, FERC proposed moving the deadline to schedule gas for the Timely Nomination Cycle from 11:30 a.m. CT to 1 p.m. CT and increasing the number of intraday cycles from two to four. NAESB’s proposals were similar: it proposed the same start time for the Timely Nomination Cycle, but it suggested moving the end time from 4:30 p.m. CT to 5 p.m. CT. NAESB also added one extra intraday cycle to the proposal, instead of FERC’s two.
But the standards board was unable to bring the two industries to an agreement regarding the gas day, with electric favoring the earlier gas-day start time so it more closely aligns with the electric day, and gas saying the time change is unneeded and may be disruptive to gas markets.
Battle Lines Remain in Place
In its late September filing detailing its modifications, NAESB said that stakeholders on the Gas Electric Harmonization Committee had narrowed 13 proposals to four, each containing identical cycle schedules but different gas-day start times.
“Despite forum participants casting over 13,000 votes on 56 different motions, no single proposal gained the supermajority support required of both [electric and gas] quadrants to reach consensus on a single proposal,” NAESB said.
The board instead left the start time question up to FERC, submitting a proposal with the provisions that had common agreement while replacing all references to the start time in the standards with a question mark.
While some stakeholders suggested minor alterations to NAESB’s proposed cycle schedules, they each fell into one of two camps when it came to the gas day start time.
“Changing the start of the gas day is unnecessary to achieve the commission’s objectives in this proceeding and could create unintended adverse consequences to the natural gas industry,” said the Natural Gas Council, which represents companies in all segments of the gas supply chain. In comments filed late last month, the council urged FERC to adopt NAESB’s proposed cycle schedules, which it said would address generators’ concerns over running out of gas toward the end of the gas day, as demand for electricity ramps up during the morning.
The council also noted the regional disparity between generators who wanted an earlier start time, with those on the West Coast siding with the gas industry in maintaining the status quo. The proposed change would mean a 2 a.m. PT start time.
“Disrupting the entire natural gas market by moving the start of the gas day would be an overwhelming undertaking,” the council said. “The commission should not require a change to the national gas day to address a problem that is more limited and regional in nature.”
RTOs, meanwhile, support the earlier start time.
“The current start of the gas operating day … requires electric generators to nominate gas over two electric days. Gas scheduled during the day-ahead Timely Nomination Cycle covers the evening peak of one electric day, and the morning electric ramp of the following electric day,” the ISO/RTO Council said in its comments. “Schedules for the second electric day, which correspond to the morning electric ramp, are not yet known when generators nominate gas. Moving the gas operating day to an earlier time would allow generators to nominate gas in the day-ahead Timely Nomination Cycle, i.e., the most liquid cycle, to cover the morning electric ramp and the evening peak of a single electric day.”
The IRC represents all nine RTOs in North America, including CAISO, which the council said also supported an earlier start time. A number of RTOs filed their own comments as supplements to the IRC’s.
“Moving the gas day to 4 a.m. CT or earlier, coupled with changing the Timely Nomination Cycle to 1 p.m. CT, will enable owners of gas-fired generators needed for the peak morning period to timely nominate and schedule gas supply to support their ability to generate electricity at the start of the morning peak,” said ISO-NE, which noted New England’s heavy reliance on natural gas and its past difficulties procuring it.
MISO and SPP also voiced their support for the earlier start time, with SPP also proposing an even later start to the Timely Nomination Cycle.
Representing Diverse Views
Some stakeholders stayed neutral in the start-time discussion, as their membership was too diverse and divided to take a position on either side of the issue.
In its comments, the Electric Power Supply Association, which represents players in both the gas and electric industries, said it supported NAESB’s modifications and that it could not support either start time because its members were divided. But it also noted that there was a broad consensus on one aspect of the start time.
“While there are EPSA members on each side of this issue in terms of the 4 a.m./9 a.m. debate, there is clear consensus that some other time between 4 a.m. and 9 a.m., or different times set for different regions of the country, is not acceptable or workable,” EPSA said.
The Edison Electric Institute, which represents U.S. investor-owned utilities, also refrained from taking a position on the gas-day, but did offer support for NAESB’s modifications. It also urged FERC, regardless of what it decides, to “provide the necessary lead time to ensure that the changes are made in a coordinated manner that maintains the reliability of both the electric and the natural gas systems.”
EEI recommended that FERC implement the changes during a “shoulder month,” preferably in the spring, when demand isn’t as high.
PJM’s new graduated queue-entry cost structure has not persuaded interconnection customers to file their requests earlier, PJM officials told members last week.
About 54% of the project applications in the queue that closed Oct. 31 (AA1) came in the final month, and 43% of those came in the final week — 26% on the final day — said David Egan, manager of interconnection projects. In the previous queue, before the fee structure was changed, 47% of applications came in the final month.
“This is not workable,” said Steve Herling, vice president of planning. “It hasn’t really improved with the changes we’ve made.”
Under the new structure, the deposit for applications filed in the first four months was set at $10,000; for the fifth month, $20,000; and for the last month, $30,000.
“I’m noodling on a method to fix this. That is going to be a proposal that we bring to better allow my group to handle it,” Egan said, inviting suggestions to incent early participation. “This is creating big chunks of work, and invariably things get dropped or missed.”
Projects totaling about 30,000 MW are currently under study, with another 19,000 MW under construction. Natural gas accounts for 80% of the total. PJM received 2,376 project applications in the queue. Of that, 23% are in-service and 172 agreements were terminated.
TO/TOP Matrix
Members approved Version 8 of the TO/TOP (Transmission Owner/Transmission Operator) Matrix, the result of an annual review. The document serves as an index between PJM manuals and North American Electric Reliability Corp. standards and creates no new obligations for PJM or its members.
