A repeat of last winter’s polar vortex should not imperil the nation’s power system, the North American Electric Reliability Corp. said last week. Lessons learned from last year’s extreme weather and subsequent operational reviews have left the U.S. better prepared compared to early 2014, NERC said in its 2014-2015 Winter Reliability Assessment.
“Last year, the system bent, it twisted, but it didn’t break,” John Moura, NERC’s director of reliability assessments, said in a press briefing Friday. He said various scenario analyses of weather, and fuel resource and plant availability, were run to recreate January’s polar vortex under current operational conditions.
NERC concluded that “all areas appear to have sufficient resources,” he said. Moura noted familiar themes: an increased reliance on natural gas could cause fuel constraints and limit the availability of some plants during cold snaps.
While New England is “at the forefront of concern” for areas with heavy reliance on gas, he said significant progress has been made in addressing that need through ISO-NE’s winter reliability program. (See ISO-NE in Precarious Position for Winter.)
Moura said that coal delivery and supplies have become concerns in the Midwest and elsewhere that require monitoring, but he characterized it as isolated to relatively few plants and a low risk to grid reliability.
New PJM Demand Record
Hints of the coming winter hit PJM Nov. 18 when unseasonably low temperatures pushed the RTO beyond its previous November demand record. The preliminary peak demand was 121,987 MW at 7 p.m. Real-time prices topped $200/MWh throughout much of PJM at 6 p.m., with the Dayton Power and Light zone highest at $287. The previous November record, set in 2013, was 114,699 MW.
(Click to zoom)
New England got some good news last week from the latest National Oceanic and Atmospheric Administration 90-day forecast, which said that slightly higher temperatures than previously forecasted are expected in the region. Chances for slightly drier weather have increased along the Great Lakes and in the Ohio Valley. However, the probability of above-normal levels of precipitation along the eastern seaboard up to southern New England has increased.
FERC Query on RTO Fuel Assurance
Meanwhile, the Federal Energy Regulatory Commission on Nov. 20 ordered RTOs and ISOs to file reports within 90 days on their efforts to ensure generators have adequate fuel (AD13-7, AD14-8).
This topic has been on FERC’s radar since at least 2013 but became more acute after last winter, as natural gas generators faced price spikes and an inability to obtain fuel. The high prices meant dual-fuel capable plants in New York and New England burned unexpectedly large amounts of oil.
The following items were approved by members Thursday with little discussion or opposition:
Markets and Reliability Committee
Interchange Limits Approved
The MRC approved PJM’s proposal to limit interchange during emergency conditions by acclamation, with five objections. An MRC sector-weighted vote last month on the issue fell just short of a two-thirds approval. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)
To address concerns raised by PJM’s Independent Market Monitor, the proposal was revised to include language to address hoarding and manipulation of interchange “room.” The rule is intended to prevent markets and operations from being whipsawed by large swings in imports.
In a related matter, the Members Committee approved revisions to Manual 11, Manual 28 and the Tariff concerning energy and reserve pricing.
Gas Unit Commitment Rules OK’d
Members approved changes to gas unit commitment rules, including a provision allowing generators to change their offers to reflect fluctuating fuel prices. Generators will be able to lock in their fuel prices three hours in advance of the operating hour. Officials said the increased flexibility will require software changes that should be complete in January.
The option will be available to resources that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time will be unable to change their cost schedules until released. (See PJM Members Approve Intraday Updates to Generator Cost Schedules.)
PJM conducted training for system dispatchers yesterday on the changes.
Sampling to be used for Measuring Residential DR
Members approved a proposal allowing PJM to measure the demand response performance of some residential customers through sampling of interval-meter data. The new measurement method will replace outdated studies dating back to 2001.
The change won support of almost 81% of members on a sector-weighted vote. It was approved over opposition by Market Monitor Joe Bowring, who said sampling would not be as accurate as metered data. “We know when generators fail to respond because they are metered,” Bowring said. “The same will not be true here.”
PJM officials said sampling will improve accuracy without the cost of installing one-minute meters on every participating household. PJM’s Shira Horowitz said the new method builds on an “extremely successful” pilot program.
FirstEnergy’s Jim Benchek also opposed the change, saying it was a “carve out” for DR. He also said it was “inappropriate” to continue incorporating DR in the wholesale market in light of the D.C. Circuit Court of Appeals’ EPSA ruling, which concluded that DR in the energy market fell under the jurisdiction of the states and not under the Federal Energy Regulatory Commission’s authority over wholesale markets. (See New Measurement Rules for Residential DR OK’d; FirstEnergy Opposes.)
Seller Credit Eliminated
Members agreed to eliminate the “seller credit” provision from its credit policy, which RTO officials said was no longer needed. The provision was enacted when PJM still used monthly billing, to allow participants with consistent net sell positions some unsecured credit. Due to changes in credit policy and the 2009 switch to weekly billing, the need for seller credit is now addressed by the Reliability Pricing Model seller credit, a larger and less volatile credit, PJM said.
Manual Changes
Manual 3: Transmission Operations — Updates names; clarifies timing for load shed for post-contingency voltage collapse; updates several sections; adds procedures.
Manual 13: Emergency Operations — Clarifies actions taken prior to emergency procedures; adds Min Gen Advisory procedure; updates Cold/Hot Weather Alerts; revises geomagnetic disturbance procedure; condenses and consolidates Attachment A.
Manual 11: Energy & Ancillary Services Market Operations — The change will allow PJM to relieve demand response resources of their regulation and synchronized reserve responsibilities during Load Management Events. The change addresses the inability of DR resources to provide ancillary services and load management simultaneously.
Manual 14B: PJM Regional Transmission Planning Process — Changes made in accordance with North American Electric Reliability Corp. standards PRC-023-3 (Transmission Relay Loadability) and TPL-001-4.
Manual 28: Operating Agreement Accounting — Revised to include Load Reconciliation data in the settlement of emergency load response and emergency energy billing.
Manual 29: Billing — Changes method of reimbursing treatment of underpayments of miscellaneous items and special adjustments to avoid cost shifts. In cases of shortages those parties due payments would be “short paid” on a pro-rata basis. Shortages will not be socialized among all members.
Manual 13: Emergency Operations — Updates the 2015 day-ahead scheduling reserve requirement to 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%).
Members Committee
The committee approved:
Operating Agreement (OA) revisions to ease Transmission Owners’ access to generator data feeds.
Updated Installed Reserve Margins and related metrics for 2015/16 through 2018/19 delivery years.
Non-substantive revisions to definitions in the Tariff and OA, aimed at providing alignment of definitions between the documents.
PJM stakeholders deadlocked for the third time Thursday on changes to the $1,000/MWh energy offer cap, leaving it to the Board of Managers to decide whether to seek Federal Energy Regulatory Commission approval of any changes.
Old Dominion Electric Cooperative’s Ed Tatum withdrew a compromise proposal to raise the cost-based offer cap to $1,800 in the face of opposition from load representatives following a lively Members Committee debate.
Members’ inability to reach consensus means the board would have to make a unilateral Section 206 filing to win FERC approval for any change.
PJM CEO Terry Boston expressed disappointment. “I was hopelessly optimistic that we could get to a [Section] 205 filing,” he said.
“There will be other times” when the cap is exceeded, Boston said. “I really don’t like the idea that we hold in abeyance until we have an emergency. … We don’t want to be in the position that we have to run to FERC and ask for a 24-hour decision.”
In January, FERC granted the RTO’s request for a waiver, allowing make-whole payments for generators with operating costs exceeding $1,000. PJM said the waiver was necessary to allow some gas-fired generators to cover costs above the cap, as spot gas prices spiked as high as $140/MMBtu.
Earlier this month, Calpine Energy Services requested that FERC allow it to recover about $3.3 million it said it spent on expensive gas for two generating units at PJM’s direction and was unable to burn when the RTO cancelled their plants’ dispatches (ER15-376). Calpine’s claim is similar to those filed earlier by Duke Energy, which is seeking $9.8 million for “stranded” gas (EL14-45) and Old Dominion, which is seeking $2.7 million (ER14-2242). (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)
In April, PJM members agreed to form a task force to consider changing the cap. The group was unable to reach consensus after nine meetings and has since disbanded.
The proposal presented Thursday resulted from negotiations led by Tatum and Mike Borgatti, of Gabel Associates, who represented generators. It would have allowed cost-based offers between $1,000/MWh and $1,800/MWh to set LMPs. Generation costs above that cap would be recovered through uplift.
Maximum market-based offers would be capped at $1,000 or the cost-based offer.
The majority of members who spoke Thursday strongly opposed the changes. Even those who encouraged the proposal’s passage conceded they supported it only as a better alternative to losing control over the matter to FERC. A 205 filing also would show a cohesiveness among the group, they said.
“This is not a proposal that Old Dominion would have come up with,” Tatum said in making his presentation. But, he said, “I think we’ve gone as far as we can go with this.”
Susan Bruce of the PJM Industrial Customer Coalition said her group opposed the proposal. “There is a lack of evidence of a systemic problem,” she said.
Market Monitor Joe Bowring said fewer than 25 offers breached $1,000 in January. While some of the proposed offers were in the $1,700/MWh range, Bowring said there were no legitimate offers greater than $1,400/ MWh.
Walter Hall, representing the Maryland Public Service Commission, said Tatum’s proposal represented not a “compromise” but a concession to generators’ attempts to profiteer.
“We fear this is a profit-making opportunity [for generators], not a cost-recovery opportunity,” he said. “Why should everyone profit from something of that nature?”
Jim Jablonski of the Public Power Association of New Jersey referred to the Market Monitor’s March 26 report to FERC, which concluded that only $9,118 of $583,774 in additional compensation sought by seven units in three PJM control zones when gas prices peaked in January was legitimate.
And, he said, “that was at the worst of times. I certainly don’t see the justification for above $1,000.”
Carl Johnson, representing the PJM Public Power Coalition, said approving the Tatum-Borgatti proposal would have been preferable to “throwing a jump ball at FERC.”
“It’s not perfect, but it is way better than that outcome,” he said.
J.P. Morgan Ventures Energy’s Bob O’Connell, who had debated Tatum over the issue at the October MC meeting, said he came into Thursday’s forum opposed to the newest proposal. (See Load, Supply Trade Blame over Offer Cap Impasse.)
But, he said, “the deal you see on the table is a deal that can get done. This is not about getting what you want — it’s about not getting what you don’t want.”
State-by-state compliance with the Environmental Protection Agency’s (EPA’s) proposed carbon emission rule would be almost 30% more expensive than a regional approach, according to preliminary results of PJM analyses.
The analyses included eight scenarios requested by the Organization of PJM States (OPSI) and seven proposed by PJM.
One analysis (PJM scenario 4), which included existing fossil resources and planned resources with interconnection service agreements (ISAs) and facility study agreements (FSAs), estimated a 2020 carbon price of $11/ton under state compliance, compared with $2/ton under a regional approach.
PJM determined the CO2 emissions prices based on the price differential needed to ensure the RTO’s economic dispatch displaced enough high-emitting generators with lower-emitting generation to reach the emissions targets.
The regional approach sets a single carbon price for all fossil fuel generators in PJM. Under state compliance, each state would have a different carbon price. Indiana and West Virginia would face the highest carbon prices under a state-by-state approach, with prices exceeding $14/ton, while it would cost Maryland and Virginia only about $5/ton.
Under a regional plan, “states have the ability to trade reductions among each other to achieve lower costs of compliance,” explained Chief Economist Paul Sotkiewicz. Sotkiewicz and PJM engineer Muhsin Abdur-Rahman presented the preliminary results of the analyses at the Members Committee webinar last week.
Total compliance costs would near $45 billion in 2020 under the state approach, versus $35 billion using regional compliance.
Mass-to-Rate Conversion
PJM initially did the analyses based on the implied mass-to-rate conversion in the EPA’s June 2 proposed rule. It redid the calculations based on revised guidance the agency provided Nov. 6, which sets a declining mass target over the interim compliance period (2020-2029) and does not credit new renewables and incremental energy efficiency.
Under the revised conversion, most of the scenarios estimated carbon prices of about $5 to $10 per ton in 2020, rising to $20 to $30 per ton in 2029.
One scenario (PJM #8) saw carbon prices starting at about $40/ton in 2020 and rising to almost $60/ton by 2029. The scenario adjusted planned natural gas capacity based on historic commercial probabilities (greater than 70% for projects with ISAs, greater than 50% for those with FSAs), reduced new combined-cycle capacity to not exceed the installed reserve margin target and assumed a 50% increase in gas prices.
The analyses found that a rate-based approach would result in lower LMPs than a mass-based measurement, meaning generators will need to collect more in capacity revenues. There were little or no increases in LMPs for many scenarios.
The Federal Energy Regulatory Commission won’t wait for PJM stakeholders to develop rules to prevent fleet owners from receiving reactive power payments for retired generators.
FERC last week ordered PJM to revise its Tariff to address the issue within 30 days or show cause why it should not be required to do so (EL15-15).
A frustrated Vince Duane, PJM general counsel, told members Thursday that FERC’s action appeared to be prompted by the “fairly contentious” process that preceded the Markets and Reliability Committee’s approval last month of a problem statement to address the issue. “They’re not prepared to wait for this group to go through those issues,” he said.
The problem statement included language suggested by Public Service Enterprise Group, which complained that the original statement assumed that fleet owners are being overpaid if they failed to file revised cost schedules with FERC after plant retirements. PJM officials said they did not know how much ratepayers might be overpaying. (See PJM Members Seek Fix for Payments to Retired Plants.)
Duane said it was not certain whether PJM will file proposed Tariff revisions within 30 days or seek more time. But he added that the issue was “not going to be addressed through the stakeholder community — at least not exclusively.”
The commission said it was acting because PJM’s Tariff lacks explicit provisions to end reactive power payments for generators that are retired or sold.
FERC said it also had asked its Office of Enforcement “for further examination and inquiry as may be appropriate” for owners that may have received payments for retired units. Any refunds resulting from the order will be dated from when the Nov. 20 order is published in the Federal Register.
The commission cited a filing in which FirstEnergy “asserted that the commission and the PJM Tariff are silent about updates to reactive service revenue requirements when units are deactivated or transferred out of a fleet, but that ‘parties may agree among themselves regarding the allocation of revenues with respect to changes in ownership.’”
FERC also cited the Sept. 24 request of Sunbury Generation to terminate the reactive service tariff for its retired 436-MW coal-fired facility in Snyder County, Pa. FERC noted that Sunbury had closed the plant more than two months before its filing. PJM told the commission it was still paying for reactive power on the retired plants.
The commission Thursday approved Sunbury’s cancellation request and required it to refund any payments received for the period after the plant deactivation (ER14-2936).
The Federal Energy Regulatory Commission yesterday approved Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc., dismissing concerns from PJM stakeholders of increased market power, adverse effects on competition and increased rates.
With approvals from FERC and the Virginia State Corporation Commission in hand, Exelon still must win approval from regulators in D.C., Maryland, Delaware and New Jersey. “We did consider all of the issues that came in with respect to … the PJM stakeholder process. We felt it met the tests of [the Federal Power Act] with the effects on rates, the effects on regulation and the effects on competition,” FERC Chairman Cheryl LaFleur said after the commission’s monthly meeting yesterday.
FERC did not place any conditions on its approval of the merger, such as requiring that Exelon stay in PJM, as requested by the Independent Market Monitor, or that the companies not be allowed to recover any merger-related costs through rates, as the Delaware Public Service Commission requested.
FERC noted that Exelon committed to staying in PJM for 10 years after its 2012 merger with Constellation Energy Group as a condition of the Maryland Public Service Commission’s approval of that deal. The commission said it would address market power concerns if and when Exelon left PJM after 2022.
FERC also noted that the companies have committed to hold transmission customers harmless for any merger-related costs for five years after the merger is completed. After that, FERC said, the companies must file a request to recover these costs through rates, at which point “the commission will determine whether applicants have demonstrated offsetting savings to customers served under commission jurisdictional rate schedules such that recovery of merger-related costs would be appropriate.”
In its order approving the deal (EC14-96), FERC largely echoed the two companies’ rebuttals of protests from the Monitor, the Delaware PSC, Southern Maryland Electric Cooperative and other PJM stakeholders. (See Exelon, Pepco Reject Merger Objections.)
In its response to these rebuttals, the Market Monitor had argued in early September that FERC should require from the companies more information and analysis showing how the merger would not adversely affect competition in PJM’s capacity market through their combined demand response resources. It also said the companies did not address vertical market power concerns in their analyses.
FERC disagreed, however, saying that the information provided by the companies was sufficient. It said Pepco’s additional 700 MW of demand resources would be too small to affect competition in PJM’s capacity market, noting that Exelon already controls 26,000 MW of generation, DR and energy efficiency. The commission also pointed to a Sept. 19 filing from the companies in response to the Monitor’s claims, which the commission said “provided additional information regarding the limited ability of Pepco Holdings’ demand response resources to participate in the PJM energy market.”
“While we recognize that the combination of Exelon’s and Pepco Holdings’ capacity market-based demand response resources increases the market share owned by [the companies], we believe that the recent improvements to the dispatch and pricing of capacity market-based demand response resources will encourage competition among providers and lead to more efficient dispatch going forward,” FERC said.
FERC also agreed with the companies’ contention that the deal would not affect vertical competition, as Pepco owns only 17 MW of generation, and the only Pepco utility joining Exelon that distributes natural gas is Delmarva Power & Light, which does not supply any generation facility.
Both the D.C. Office of the People’s Counsel and the Delaware PSC had raised concerns about the potential adverse effects the merger would have on the PJM stakeholder process. The OPC worried that the new company’s subsidiaries would give it an increased influence on stakeholder decisions, while the PSC was concerned that PJM would lose a consistent consumer advocate in discussions (See Pepco to Lose its PJM Voice; Consumers Lose Frequent Ally.)
FERC disagreed, again echoing Exelon and Pepco. “While the commission is aware that Exelon will be a member with more assets after the merger, there is nothing in the record of this proceeding to indicate Exelon will have excessive influence over the stakeholder process or the independence of PJM,” the commission said. It noted that the new company would only have a single vote as a transmission owner in PJM’s senior committees.
The commission did not discuss the merger at its meeting. LaFleur said this was because the commissioners felt that other items on the agenda such asthe North American Electric Reliability Corp. standards and the 2014 Report on Enforcementwould benefit from discussion, while its decision on the merger was sufficiently explained in the order. She added that due to the packed schedule, she feared that the meeting would run late; it lasted an hour and a half after four discussions.
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 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 3: Transmission Operations — Updates names; clarifies timing for load shed for post-contingency voltage collapse; updates several sections; adds procedures.
Manual 13: Emergency Operations — Clarifies actions taken prior to emergency procedures; adds Min Gen Advisory procedure; updates Cold/Hot Weather Alerts; revises geomagnetic disturbance procedure; condenses and consolidates Attachment A.
Manual 11: Energy & Ancillary Services Market Operations — The changes will allow PJM to relieve demand response resources of their regulation and synchronized reserve responsibilities during Load Management Events. The change addresses the inability of DR resources to provide ancillary services and load management simultaneously.
Manual 14B: PJM Regional Transmission Planning Process — Changes made in accordance with North American Electric Reliability Corp. standards PRC-023-3 (Transmission Relay Loadability) and TPL-001-4.
Manual 28: Operating Agreement Accounting — Revised to include Load Reconciliation data in the settlement of emergency load response and emergency energy billing.
Manual 29: Billing — Changes method of reimbursing treatment of underpayments of miscellaneous items and special adjustments to avoid cost shifts.
Manual 13: Emergency Operations — Updates the 2015 day-ahead scheduling reserve requirement to 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%).
The MRC will be asked again to approve PJM’s proposal to limit interchange during emergency conditions. An MRC vote last month on the issue fell just short of a two-thirds approval. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)
The proposal to be voted on includes language to address hoarding and manipulation of interchange “room,” in order to address concerns raised by the Market Monitor.
PJM officials said they intended to recommend operating under the new rules, which require only a manual change, with or without the two-thirds mandate. The rule is intended to prevent markets and operations from being whipsawed by large swings in imports.
4. GAS UNIT COMMITMENT (10:00-10:20)
Beginning in January, gas generators will be able to change their offers to reflect fluctuating fuel prices, under a proposal being brought to the MRC. The proposal would allow generators to lock in their fuel prices three hours in advance of the operating hour.
The option would be available to resources that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time will be unable to change their cost schedules until released. (See PJM Members Approve Intraday Updates to Generator Cost Schedules.)
5. SELLER CREDIT (10:20-10:40)
Members will be asked to endorse PJM’s plan to eliminate the “seller credit” provision from its credit policy, which RTO officials said was unnecessary. The provision was enacted when PJM still used monthly billing, to allow participants with consistent net sell positions some unsecured credit. Due to changes in credit policy and the 2009 switch to weekly billing, the need for seller credit is now addressed by the Reliability Pricing Model seller credit, a larger and less volatile credit, PJM said.
6. RESIDENTIAL DEMAND RESPONSE: PARTICIPATION IN THE PJM SYNCHRONIZED RESERVE MARKET & MEASUREMENT AND VERIFICATION FOR ENERGY AND LOAD MANAGEMENT (10:40-10:55)
The committee will be asked to endorse a proposal that PJM begin measuring the demand response performance of some residential customers through sampling of interval-meter data. (See Operating Committee Briefs, Nov.11.)
7. DEFINITIONS IN GOVERNING DOCUMENTS (10:55-11:10)
Members will vote on non-substantive revisions to definitions in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35: Definitions and Acronyms. The changes are intended to align the documents.
Members Committee
2. CONSENT AGENDA (1:20-1:25)
The committee will be asked to approve the following:
Operating Agreement (OA) revisions to ease Transmission Owners’ access to generator data feeds.
Updated Installed Reserve Margins and related metrics for 2015/16 through 2018/19 delivery years.
Approve/endorse proposed non-substantive revisions to definitions in the Tariff and OA, aimed at providing alignment of definitions between the documents.
3. ELECTIONS (1:25-1:30)
The committee will elect members to the 2015 Finance Committee and sector whips, and the Members Committee vice chair.
PJM has identified 20 candidates for “market efficiency” projects in the competitive window that opened Oct. 30.
The candidates, which were presented to the Transmission Expansion Advisory Committee this morning, were based on annual simulated congestion frequency of at least 25 hours in the 2019 and 2022 study years.
They include 17 lower voltage facilities with a minimum of $1 million congestion in the study years and two regional facilities — AP SOUTH Interface l/o Black Oak-Bedington and AEP-DOM Interface l/o Black Oak-Bedington — with at least $10 million in congestion.
PJM said facilities below the thresholds were not likely to pass the minimum 1.25:1 benefit-cost criteria.
The RTO will also accept proposals to address capacity import limitations and thermal overloads on the Roseland-Cedar Grove-Clifton 230-kV corridor.
Artificial Island Update
PJM staff plans to announce its revised recommendation on the Artificial Island stability project at the Jan. 8 TEAC meeting, prior to a February recommendation to the Board of Managers. PJM will allow the four finalists to make presentations at a special TEAC meeting to be scheduled the week of Dec. 8. (See Two of 4 Artificial Island Finalists Offer Cost Caps.)
Summer 2014 was the mildest in the last 10 years based on the peak day heat index. None of the five highest load days (blue bars) were above the 10th percentile of PJM’s forecast summer peak. For the first time since 2008, the RTO’s peak day was in June. (Source: PJM Interconnection LLC) (Click to zoom.)
Cooler summer weather took a toll on electric-utility earnings in the third quarter. While some companies, such as FirstEnergy, posted increased profits compared to Q3 last year, many noted a drop in operating earnings due to a dip in deliveries to residential, business and commercial customers.
PJM reported last week that Summer 2014 was the mildest in the last 10 years based on the peak day heat index. (See chart.)
FirstEnergy
Despite its weather-related reduction in operating earnings, FirstEnergy posted a 52.8% increase in profits for the quarter, with earnings of 79 cents a share on income of $333 million, compared to 52 cents on $218 million for the same period last year.
This time a year ago, the company reported a $254 million charge on a regulatory rider rejected by the Pennsylvania Public Utility Commission. It was also in the midst of reorganizing its business units, having decided to retreat from the competitive retail market to concentrate on generation and regulated businesses such as transmission.
CEO Anthony J. Alexander said the strategy is paying off. “We have continued to build positive momentum in our regulated businesses and limit risk at our competitive operations,” he said in a conference call. He also praised PJM’s Capacity Performance proposal. “This is a positive step and truly recognizing the role of base-load generation with firm fuel, the grid stability and reliability.”
Alexander said that one of its largest generating assets, the 2,400-MW Bruce Mansfield coal plant in Shippingport, Pa., failed to clear the most recent PJM capacity auction. That was one of the reasons the company is holding back on capital improvements to that plant “while we evaluate the strength of competitive markets.”
NRG
NRG Energy’s net income rose to $168 million, or 48 cents a share, compared to $119 million, or 36 cents a share, a year ago. While some of the increase was due to the success of its retail business, it was tempered by the mild summer.
“Under these weather circumstances, I think our financial results were as good as could be expected,” CEO David Crane said. “While NRG’s financial performance was constrained in the third quarter by an absence of summer weather events, NRG’s underlying performance across our wholesale and retail operations was quite strong.”
Crane highlighted successes in many areas of NRG’s wide-ranging business model, which includes retail operations, wholesale generation and an increasing amount of renewable energy, especially solar. He said the integration of the assets from its purchases of Edison Mission Energy and Dominion Energy Solutions’ retail operations were on track. He also announced a 440-MW generation contract with Southern California Edison.
The company will continue to build its solar business – especially home solar. “We now believe we have the premier one-stop shop for customers seeking a high-quality solar experience at their homes,” he said. “By the end of this year, we expect to have over 10,000 installations, which is about 70 MW. By the end of 2015, we expect to grow that amount by three times, with an objective of a total of 35,000 to 40,000 installations, or roughly 280 MW.”
Duke
Duke Energy reported earnings of $1.27 billion, compared with $1 billion a year ago, translating to $1.80 a share. About 43 cents of that was from the sale of Midwest power plants to Dynegy for $2.8 billion. Because it had expected to sell those plants for between $1.5 billion to $2.5 billion, the price paid by Dynegy represented an unexpected gain of about $475 million. Discounting that, earnings were about $1.40 a share, down 6 cents from a year earlier.
Earnings from its regulated utilities, which make up about 90% of its business, were nearly unchanged from a year ago despite a slight increase in the number of customers throughout its territories. “These results were impacted by milder than normal weather,” CEO Lynn Good said.
She said the company continues to invest in gas-fired generation, pointing to a proposed 1,640-MW plant in Citrus County, Fla., and uprates of 220 MW at an existing plant in Hines County, Fla. The company is eyeing the purchase of a Calpine facility in Florida and plans to add 320 MW to its Suwanee plant.
A major cost is on the horizon, however. Duke also announced last week that it estimates the cost of complying with North Carolina’s coal-ash law would be as much as $3.4 billion. Hundreds of tons of coal ash spilled from a Duke site on the Dan River in February, spurring a legislative effort to force the company to clean up all of its 32 coal-ash basins.
PSEG
Of the companies operating in the Mid-Atlantic region, Public Service Enterprise Group proved the exception to the mild summer, posting both net and operating earnings increases. Net income was $444 million, or 87 cents a share, up from $390 million and 77 cents a year ago. Operating earnings rose to $393 million, or 77 cents a share, from $385 million, or 76 cents, a year ago.
“PSEG performed well in the third quarter despite the impact on demand for electricity due to less favorable weather conditions,” CEO Ralph Izzo said. “Lower operating costs helped to offset the impact of mild weather on energy pricing and earnings. We’re in the midst of major change in the electricity market. An unprecedented amount of capacity is expected to retire over the next two years in response to environmental requirements and market economics.”
PSEG’s generation arm’s numbers drooped slightly, reporting earnings of $171 million, or 34 cents a share. Last year, it earned $221 million, or 43 cents a share. Power earned less this quarter, in part because of lower PJM capacity prices, “as well as lower market prices for energy,” said Caroline Dorsa, PSEG’s chief financial officer. PJM capacity prices dropped to an average level of $166/MW-day on June 1, 2014, from $242/MW-day in the prior capacity year.
But Izzo said its generating fleet is well positioned to earn in the changing market. “Power is well situated,” he said. “Its fleet of base-load intermediate and peaking generating assets benefits from access to low-cost gas in the summer and from price volatility in the winter.”
Izzo also announced plans for a 450-MW combined-cycle plant in the New England market, at its Bridgeport Harbor site, a $600 million investment. “The potential investment in Bridgeport Harbor would represent the latest of several opportunities for PSEG,” he said.
Calpine
With its wide-ranging assets and foothold in several markets, Calpine wasn’t hemmed in by the mild Mid-Atlantic summer. It reported profit of $614 million, or $1.52 a share, compared to $306 million, or 70 cents a share, a year ago. Operating revenue rose 6.7% to $2.19 billion.
“Calpine delivered another strong quarter both operationally and commercially, especially considering the mild summer weather in much of the country,” said Thad Hill, Calpine’s President and Chief Executive Officer. “Our hedging activity protected us from a very mild summer,” he said. Hill noted that Calpine continues to build business and gain customers in Texas and California, and sell its power from its Osprey plant in Florida to Duke Energy.
He said Calpine expects to close on the purchase of the Fore River plant in Weymouth, Mass., from Exelon any day, and is expanding its combined-cycle plant near Delta, Pa. Those two facilities illustrate Calpine’s reach in both the PJM and the New England markets.
“We believe that PJM and New England offer upside to strong operators willing to stand behind their operational performance, and that the new capacity and market structures under discussion will prove beneficial,” Hill said. “Unlike many of our peers who have pushed back against some of the proposed changes, we’re willing to take the downside risk when you can’t perform with the possibility of higher compensation if you can.”
AES
Weather was a big factor in the earnings for AES, parent company of Dayton Power and Light and Indianapolis Power and Light. But it wasn’t mild summer temperatures that hurt its bottom line; it was low rainfall in Central and South America.
AES reported earnings of $488 million, or 67 cents a share, compared to $175 million, or 23 cents, last year. Overall revenue rose to $4.44 billion from $4 billion last year. About $382 million was from asset sales, including $161 million for four wind projects in the United Kingdom and $125 million for its stake in a Turkish hydro and natural gas-fired generation joint venture. (Since 2011, AES has sold $2.4 billion worth of assets in nine countries.)
Adjusted for these and other transactions, earnings were 37 cents a share. Operating earnings were down 5.1% to 39 cents a share, primarily for “persistent drought” in Latin America, where CEO Andres Ricardo Gluski Weilert said conditions are the driest in 50 years. AES has many hydro-electric assets in Panama and Brazil. “Poor hydrology in Latin America has had a substantial impact on our earnings over the past two years,” he said.
In its U.S. operations, Weilert highlighted its plans to build 1,284 MW of gas-fired combined-cycle generation in California, and the recent awarding of a contract for 100 MW of battery-based energy storage, said to be the largest such energy storage contract in the U.S.
He also said the company is investing $332 million to convert its Harding Street plant in Indiana from coal to natural gas, and that it expected future contributions to earnings from DPL due to the ruling from the Public Utility Commission of Ohio allowing the utility to collect so-called “non-bypassable charges” on customer bills relating to transmission cost even if they have a third-party supplier. The charges were effective beginning in 2014.
Pennsylvania Governor-elect Tom Wolf speaks at his election night victory party in York. Wolf ran on a platform promising to reduce carbon emissions in the state. His election could mean Pennsylvania joining the RGGI. (Source: Tom Wolf campaign)
Having won control of the Senate and a wider margin in the House, Congressional Republicans last week threatened to use oversight hearings and appropriations bills to blunt the Obama administration’s proposed carbon emissions rule. But lacking a veto-proof majority, the GOP is unlikely to block the president’s signature environmental initiative.
The Environmental Protection Agency will be accepting comments until Dec. 1 on its proposed rule to reduce power sector carbon emissions 30% below 2005 levels by 2030. The agency will release its final rule June 1, signaling the beginning of all-but-certain legal challenges.
Some states may join those challenges rather than acquiesce and develop implementation plans for EPA approval. In Wisconsin, Republican Brad Schimel was elected attorney general after a campaign in which he vowed to sue the EPA over the rule. Republican Gov. Scott Walker, who opposes the regulation, won his reelection bid. Republicans also won gubernatorial elections in Maryland, Massachusetts, Michigan and Maine.
But Democrat Tom Wolf’s victory in Pennsylvania’s gubernatorial race gave cap-and-trade supporters hope that the state may join the Regional Greenhouse Gas Initiative — and perhaps bring in some of its neighbors as well.
Climate Change Skeptics
The EPA has had no shortage of critics in Congress since 2011, when House Energy and Commerce Chairman Fred Upton (R-Mich.) offered to give then-Administrator Lisa Jackson her own parking spot at the Capitol for her frequent appearances.
Republicans boosted their control of the House to 244-184 Tuesday; seven races are still too close to call or must be determined by a run-off election as of press time. House Majority Leader Kevin McCarthy (R-Calif.) said after the election that he will call for votes later this month on legislation that would require the EPA to make public additional scientific data to justify new regulations.
With Sen. Mitch McConnell (R-Ky.) the presumptive replacement for Nevada Democrat Harry Reid as Senate majority leader, Lisa Murkowski (R-Alaska) taking the chairmanship of the Energy and Natural Resources Committee and climate-change denier James Inhofe (R-Okla.) likely heading the Environment and Public Works Committee, “You’ll see a high level of pressure being put on the EPA,” said Joy Ditto, vice president of government relations at the American Public Power Association.
Republicans hold a 52-44 edge over Democrats in the Senate. (Two independents caucus with the Democrats; Mary Landrieu (D-La.) is facing a runoff election on Dec. 6; and Alaska Democrat Mark Begich is trailing in his race by about 8,000 votes, with an estimated 50,000 absentee and other ballots yet to be tallied.)
EPA’s Clean Power Plan “is the number one oversight target for these committees,” Scott Segal, who heads the Policy Resolution Group at Bracewell & Giuliani, said in a post-election presentation.
Inhofe, who would replace California Democrat Barbara Boxer, has compared the EPA to the Gestapo and is the author of a 2012 book “The Greatest Hoax: How the Global Warming Conspiracy Threatens Your Future.”
Murkowski has called Alaska “ground zero for climate change,” acknowledging the state is experiencing warmer temperatures and thinner ice. But she said she is unsure of the cause. On election night, Murkowski told National Public Radio that a volcano in Iceland was producing “a thousand years’ worth of emissions that would come from all of the vehicles, all of the manufacturing in Europe.”
Her statement brought a sigh from Princeton professor Michael Oppenheimer, who told NPR that Murkowski’s assertion — an apparent reference to Bardarbunga, a volcano that began erupting in August — is untrue. Oppenheimer says annual emissions from Europe are 10 times more than the annual emissions of all volcanoes put together.
Coal to Gas Switch
The EPA has won praise from even opponents of the carbon rule for its outreach efforts with states and the industry. On Oct. 28, the agency responded to criticism of the proposed rule by indicating it might consider a slower shift from coal to natural gas generation. The agency heard objections from coal-dependent states, which said the proposed interim goals might threaten electric reliability and require utilities to abandon coal generators that they recently retrofitted to meet previous EPA regulations. (See EPA Signals Flexibility on Interim Carbon Targets, Coal-Gas Shift.)
“It’s not like farm commodities, where you switch from pigs to chickens” quickly, said Patrick Kiely, CEO of the Indiana Manufacturers Association. Because manufacturing represents 30% of its gross state product — higher than all states — Indiana is particularly sensitive to electricity prices.
Segal said he anticipates tailored legislation such as riders on spending bills and use of the Congressional Review Act, which allows lawmakers to review and even block major rules by federal agencies before they take effect.
“The president would be confronted with a choice,” Segal said. “Do I essentially shut down the EPA or do I work with the Republicans in the House and in the Senate to reform my proposal?”
To nullify the EPA rule under the CRA, however, Republicans would need to win defections of about 46 Democrats in the House and 15 in the Senate to overcome a veto.
A veto override is more likely for legislation calling for approval of the Keystone XL pipeline.
New Senate Leadership
The switch in Senate control will reduce Reid’s influence over appointments to the Nuclear Regulatory Commission and Federal Energy Regulatory Commission. (See Norris Departure Opens Another FERC Seat.) It also will increase the stakes for wind power supporters hoping to win renewal of the Production Tax Credit for renewable energy during the lame duck session.
McConnell has called the administration’s quest to cut carbon dioxide emissions a major threat to Kentucky’s coal industry. But he acknowledged it will be difficult for Republicans to undo the rule.
“It will be hard because the only good tool to do that … is through the spending process, and if [Obama] feels strongly enough about it, he can veto the bill,” McConnell told the LexingtonHerald-Leader. “But I view it as a complete outrage that he could not get cap-and-trade through the Congress when he owned the place — owned the place — and decided to do it anyway.”
Although cap-and-trade is not required by the EPA rule, many experts say regional programs such as RGGI, a carbon-trading plan among the Northeast and Mid-Atlantic states, may provide states the cheapest path to compliance. The EPA estimates total compliance costs of $7.5 billion in 2020 (2011$) if states meet the requirements individually, versus $5.5 billion if all states take a regional approach. (See EPA Rule Boosts Regional Compliance, Cap-and-Trade.)
Pennsylvania’s Choice
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While the EPA will set the standards, it will be up to the states to figure out how to achieve them. The agency outlined four “building blocks” that could be part of a plan, including improving the efficiency of electric generators; increased reliance on renewables; less carbon-intensive generation; and improved energy efficiency.
Pennsylvania Governor-elect Tom Wolf won election after campaigning on a promise to reduce greenhouse gas emissions and promote development of clean energy in a state where coal and gas have reigned.
Wolf pledged to join RGGI but may face opposition from Pennsylvania’s Republican-dominated General Assembly.
Earlier this year, the legislature passed a bill that would require the state Department of Environmental Protection (DEP) to obtain legislators’ approval before submitting a state plan to the EPA. “Simply put, we cannot allow federal or state regulators the unilateral ability to make these terribly important decisions that will greatly influence our state,” state Rep. Pam Snyder, a Democrat, said last summer.
The Natural Resources Defense Council has dismissed the law as “political theater,” noting that it allows lawmakers to delay, but not block, the DEP from submitting a plan to the EPA.
The law at least gives the General Assembly an opportunity to review the plan and provide input rather than leave it to whims of state or federal regulators, said Adam Pancake, executive director of the Pennsylvania Senate’s Republican-controlled Environmental Resources and Energy Committee.
The state balked at joining RGGI several years ago over concerns that it would constrain future growth and that the state didn’t get enough credit for baseline emissions, said Derek Furstenwerth, senior director of environmental services at Calpine.
Pennsylvania’s decision to join or not will be “very influential,’’ Furstenwerth said last week during a panel discussion at the Energy Bar Association’s mid-year conference in Washington. “Without Pennsylvania, I’m not sure how you’d have Ohio or West Virginia or Virginia join,” he said.
Former DEP Secretary John Hanger, now an attorney at Eckert Seamans, said Wolf could reach an agreement with Republicans to join RGGI. Hanger noted bipartisan success in passing a number of environmental regulations over the years. The state is not only a “powerhouse” in coal and natural gas but also No. 2 in nuclear power and among the top 15 ranking for renewables, he said.
Fracking Votes
Fracking was also an issue on ballots in Pennsylvania — Wolf has called for a 5% severance tax on natural gas drilling in the state – and at least three other states. In Ohio, voters rejected three of four local fracking bans, while prohibitions were approved by Denton, Texas, and two California counties, San Benito and Mendocino.
Meanwhile, fracking advocates say Republican gains in New York’s Senate may put more pressure on Gov. Andrew Cuomo to end a moratorium on drilling.
Room for Bipartisanship?
Consultant Jeff Navin, onetime aide to former Sen. Tom Daschle, told Bloomberg News that Republicans will be under pressure to move beyond “message votes” and pass legislation that Obama can sign.
“There will be increased pressure on Republicans to legislate and to make Congress functional, especially given what’s at stake in 2016,” he said.
Some observers see the potential for agreement on a bill by New Hampshire Democrat Jeanne Shaheen and Ohio Republican Rob Portman, which seeks to boost energy efficiency for residential and commercial buildings.
Nuclear power also could find bipartisan backing. The resource, which has traditionally enjoyed Republican support, has gained some environmentalist allies because of its role as a baseload source of carbon-free generation.
And while many Republicans oppose subsidies for wind, others from rural areas that are home to wind farms have been supportive of the PTC.
Ditto said she hopes to see bipartisan support for provisions to help expand pipelines and storage to accommodate growing use of natural gas for power generation. That includes a favorable permitting climate needed to make such investments. “That’s one of our key concerns with the Clean Power Plan,” she said.
Rich Heidorn Jr. contributed to this article from Washington.
