Page 1648 – RTO Insider

March 4, 2014

Stakeholders Reject Pay Hike for Black Start Units

By David Jwanier

Black start generators anticipating increased compensation came away empty handed Thursday as stakeholders rejected two proposals that would have boosted payments to existing units by at least 40%.

The Markets and Reliability Committee split along supply-load fault lines in rejecting the proposals.

Proposals Described

The Minimum Incentive proposal, which would have increased total payments to existing black start units by an estimated $3.4 million, won only 60% support in a sector-weighted MRC vote, short of the two-thirds needed to clear. While every Transmission Owners sector member and most members of the Generation Owners sector voted in favor, the proposal failed to win a single vote from End Use Consumers and got about half of Other Suppliers and Electric Distributors votes.

An alternative proposal, the Proxy for Base Formula Replacement, which would have more than doubled costs for existing black start units, also fell short with only 45% support and no support from the EUC and ED sectors.

The proposals had garnered 65% and 63% support, respectively, in unweighted votes in the System Restoration Strategy Senior Task Force.

Existing black start units are paid a base formula rate plus an incentive. The Minimum Incentive proposal would have increased the incentive factor from 10% of the base to the greatest of 10% or $25,000. This would raise the annual payment for a 20 MW black start unit from approximately $51,000 to nearly $72,000.

The same 20 MW unit would have received $312,000 under the proxy proposal. (See Black Start Units to See More Green?)

Bowring: No Need for Increase

Market Monitor Joe Bowring and stakeholders representing load questioned the need for the increase, noting that PJM said it had received a good response to its recent solicitation for new resources.

After the Minimum Incentive proposal failed, NRG Energy’s Neal Fitch made a statement endorsing the Proxy proposal, which he said was similar to compensation methods in New England.

Dave Weaver, representing Exelon, said generators in the PECO zone “are receiving revenues that are nowhere near the proxy.”

“What’s the benefit?” asked the Delaware Public Service Commission’s John Farber.

“I would say the benefit is you don’t lose these resources,” responded Weaver.

Bowring opposed both options, eschewing the “idea of some minimum payment that isn’t based on costs.”

“We support paying black start units full costs,” he said. “This is not what this is about. This is about an artificial cost based on what other units are getting. There is no basis for the assertion that these units will go away” without an increase.

PJM’s Chantal Hendrzak said although some operating generators have stopped offering black start service recently, “we’re finding sufficient black start to meet these critical load needs” as a result of the solicitation.

After the second proposal failed, Gloria Godson, representing Pepco Holdings, called for a renewed effort to create a “back-stop” solution for zones that fail to attract sufficient black start resources. “Generators are not in the business of just breaking even,” she said.

The issue will be returned to the task force for further consideration.

March 4, 2014

Pepco Earnings Up, FE Down

By Ted Caddell

Pepco Holding Inc.’s quarterly earnings shot up to 23 cents a share on $58 million for the final quarter of 2013, compared to 15 cents a share on $34 million for the same quarter a year ago.

Year-end results were $1.14 per share on $280, compared to 98 cents a share on $225 million a year ago.

The company attributed the increase to higher electric distribution revenues — primarily from higher rates from infrastructure investments — and lower operating expenses.

“Over the past three years, decreases in the duration and number of power outages have been dramatic, reflecting the significant investments we have made in the electric system,” CEO Joseph Rigby said during a conference call Friday. “The increase in adjusted earnings in 2013 reflects the impact of these investments.”

As with many utilities announcing year-end financial results, Pepco’s regulated delivery service posted an annual increase in revenue (4 %) while its non-regulated business posted a decrease (3.4 %) for the year.

Rigby said that the company’s improvements in system reliability helped drive its improved results. Having announced his retirement in January, he’ll have little time to enjoy the upswing, however. (See Pepco CEO to Retire.)

FirstEnergy Posts Lower Q4, Year-End Results

FirstEnergy reported a decrease in both quarterly and year-end earnings for 2013, a tough announcement in a year that already saw the company cut its dividend.

The company reported fourth-quarter earnings of 75 cents per share, compared to 80 cents for the same quarter a year ago, and $3.04 for the year, compared to $3.34 the year before.

Its 2014 guidance numbers show that it’s not out of the woods, either, with first-quarter earnings estimates of 35 cents to 45 cents per share, and year-end earnings at $2.45 to $2.85 per share.

The company said increased regulated delivery revenue helped make up for lower power prices coming from its aging generation fleet.

In January, it announced it was reducing its quarterly dividend to 36 cents a share from 55 cents, the first dividend cut in the company’s 17-year history, and said it will concentrate on its regulated delivery businesses going forward. (See Reboot for FirstEnergy.)

FirstEnergy CEO Anthony J. Alexander said the company’s actions “were intended to strengthen our financial position and reposition the company to focus on more predictable and stable growth initiatives in our regulated businesses.”

The company plans to invest $4.2 billion on its transmission business over the next four years.

March 4, 2014

RPS Targets’ Cost: $13.7B in Tx Upgrades

Renewable Portfolio Standards in PJM States (Source: DESIRE)

PJM could get 30% of its energy from wind and solar power without reliability problems, but it will require as much as $13.7 billion in transmission upgrades and 1,500 MW in additional regulation reserves, according to a long-awaited study.

The results of the study, which PJM commissioned in 2011, were presented to stakeholders yesterday by a study team headed by GE Energy.

Stakeholders had asked PJM to assess the impact on grid operations of state renewable portfolio standards. PJM states have targets calling for at least 10% of their electricity from renewables by the middle of the next decade, with most states setting targets between 20% and 25%. In total, the state targets anticipate the addition of 33 GW of wind and 9.2 GW of solar by 2029 (see chart).

Ten Scenarios

The study considered 10 scenarios, ranging from a business-as-usual case based on 2011 levels of wind and solar generation to a high-end case in which nearly one-third of the region’s power was generated by those renewables.

The study looked at the impact on regulating and operating reserves, transmission upgrades, PJM markets and operations, power plant emissions and the impact of cycling duty on variable operation and maintenance (VOM) costs.

Findings

Wind and Solar Requirements in PJM (MW) By 2029 - 33 GW of Wind 9.2 GW of Solar (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

It found that PJM could adapt to the 30% renewable scenario without significant reliability problems by adding transmission and regulation reserves. “PJM has long held that ISOs and RTOs are better able to integrate variable energy resources because of their organized markets and regional infrastructure planning processes,” PJM said in its summary of the study. “… The study found that PJM’s large geographic footprint also provides significant benefit for integrating wind and solar generation because it greatly reduces the magnitude of variability-related challenges.”

All 10 of the scenarios predicted lower average Locational Marginal Prices and reduced revenues for conventional generators.

Although renewable generation increased the amount of cycling on existing generators, the increased VOM costs were small relative to the reduction in spending on fuel.

Recommendations

The study recommends that PJM:

Develop a method for determining reserve requirements based on forecasted levels of wind and solar production.
Consider intra-day unit commitments that would allow use of more efficient combined cycle units rather than combustion turbines to balance renewables’ variability. The study’s authors said that four-hour wind and solar forecasts have half the error rate of day-ahead projections.
Identify the reasons for ramping constraints on individual generators (i.e., technical, contractual, or otherwise) and seek methods for improving the flexibility of those that have traditionally operated as baseload units.

The study suggested PJM consider further study on how conventional generators can remain economically viable despite reduced energy market revenues.

It also recommended the RTO investigate how wind and solar plants could contribute to frequency response. Current wind and solar generators have the ability to respond to frequency response and down-regulation.

PJM’s Ken Schuyler, who introduced the study team yesterday, said PJM management has not taken a position on the study’s recommendations and plans to consult with members to “see which ones stakeholders think we should pursue.”

March 4, 2014

Company Briefs

American Municipal Power issued a request for proposal for carbon offset projects its six-state territory. Offsets may be from existing or new projects, including forest management, coal mine methane, landfill methane, wastewater treatment and anaerobic digestion. AMP has developed forestry offset projects and continues to pursue them, but says “carbon offset diversification is desired as well.”

More: AMP

Former Southern Exec Joins AEP Board

American Electric Power elected J. Barnie Beasley Jr. to its board of directors. Beasley, former chairman, president and CEO of Southern Nuclear Operating, is an adviser to the board of the Tennessee Valley Authority. His “nuclear operations expertise and insights into our industry will be valuable contributions to our board,” said AEP Chairman and chief executive Nick Akins.

More: AEP

— Compiled by Kathy Larsen

March 4, 2014

TOs Will Disclose Calculation Methodologies

Transmission owners will publicly post the calculations they use to allocate energy, capacity and transmission costs under a plan outlined to the Markets and Reliability Committee.

The Transmission Owners Agreement-Administrative Committee’s plan is intended to promote greater transparency, addressing a problem statement approved by the MRC last year. (See MRC Backs Industrials’ Call for Transparency in Transmission Owner Calculations.)

The proposal would add a page to the PJM website containing the methodologies transmission owners use to calculate total hourly energy obligations (THEO), peak load contributions (PLC) and network service peak loads (NSPL). The calculations are used to allocate cost responsibility among load-serving entities.

The issue arose because some TOs have not filed tariffs disclosing the methodology they use. Some members complained that the lack of transparency made it difficult to ensure they were being properly charged.

March 4, 2014

PJM Proposes Change to CONE Schedule

PJM officials told members last week they want to accelerate the schedule of the quadrennial review of the Cost of New Entry (CONE) by two months.

The proposed change would move the deadline for staff recommendations to May 15 from July 15 and the projected FERC filing to Oct. 1 from Dec. 1.

Executive Vice President for Markets Andy Ott noted that CONE calculations — which set the floor price for new generation resources looking to enter the capacity market — have been highly contentious in past years.

The two-month acceleration is “to give enough time for it to be litigated at FERC” before the capacity auction, he told the Markets and Reliability Committee.

The proposed change will be brought to a vote at the next MRC meeting.

March 4, 2014

Tariff Changes Prepare for CTS

Preparing for a new scheduling product, the Markets and Reliability Committee last week approved collateral rules for export transactions.

The changes to Attachment Q of the Open Access Transmission Tariff will apply to Coordinated Transaction Schedules, which are designed to reduce uneconomic power flows between PJM and NYISO.

Under CTS, traders would be able to submit “price differential” bids that would clear when the price difference between New York and PJM exceed a threshold set by the bidder. CTS were conditionally approved by FERC on Feb. 20 and will not be available to traders until at least November.

March 4, 2014

January Cold Almost Off the Charts

PJM’s frigid January was almost off the charts — literally.

PJM Load-Weighted LMPs (Source: PJM Interconnection, LLC)

The record-setting cold pushed PJM’s load-weighted LMP to $126.80, more than three times the price in January 2012, officials told stakeholders last week.

The RTO’s gross billings for the month were $11.2 billion — about one third of the total for all of 2013. Collateral calls for the month totaled $2.6 billion, more than six times the total for all of 2013. (See charts.)

PJM officials told the Members Committee that they are combing through data in preparation for an April 1 technical conference called by the Federal Energy Regulatory Commission.

January 2014 Billing & Collateral Activity (Source: PJM Interconnection, LLC)

Acting FERC Chair Cheryl LaFleur announced the conference Feb. 27, saying it would focus in part on the experience in PJM, which called on demand response, a voltage reduction and voluntary appeals for conservation to avoid rolling blackouts in the face of record demand and large numbers of generator outages.

Investigations Sought

Consumer advocates from the PJM states on Feb. 14 asked FERC to investigate the causes of the high prices.

“It is becoming apparent that the unprecedented energy and ancillary service prices that occurred in January were not reflective of smoothly operating market fundamentals, but were, instead, reflective of significant and systemic inefficiencies,” the advocates wrote. “For example, we know that more than 40,000 MW of generation was unavailable during critical periods in January due to forced outages. This is the same generation for which consumers in the PJM region are paying billions of dollars in capacity payments each year.”

The American Public Gas Association, which represents publicly owned local distribution companies, asked the Commodity Futures Trading Commission (CFTC) Feb. 20 to examine the cause of a 10% jump in the February 2014 New York Mercantile Exchange (NYMEX) Henry Hub contract.

The association said natural gas for February delivery jumped 52 cents to $5.557 per MMBtu, the highest closing price in more than three years, during the final hours of trading on Jan. 29.

While he said the association had no evidence of manipulation, APGA President Bert Kalisch said “We are more concerned about the pervasive pricing impact of NYMEX and want to be certain that the market is liquid and operating correctly.”

Gerald Ballinger, chairman of the group’s Gas Supply Committee, noted that most public gas companies purchase gas under contracts priced off of a price index.

Inside FERC’s Gas Market Report calculated the February price at Texas Gas Zone 1 based on a survey of 18 trades, 17 of which were basic transactions priced off of NYMEX, he said. The price rose to $5.54/MMBtu in February, compared up from $4.34/MMBtu in January.

March 4, 2014

Second Time Not the Charm

PJM’s attempt to address speculation in the capacity market collapsed Thursday as members failed for the second time in three months to reach consensus on rule changes.

The Markets and Reliability Committee was unable to muster a two-thirds sector-weighted vote for either PJM’s proposal or an alternate proposal from Old Dominion Electric Cooperative (ODEC) to eliminate opportunities to arbitrage between the Base Residual Auction and the Incremental Auctions. In all, there were four votes, including two that incorporated a late amendment addressing a potential loophole.

With the MRC deadlocked, the Board of Managers decided late Thursday to make a unilateral filing with the Federal Energy Regulatory Commission seeking approval of the PJM proposal.

Voting Blocs

The MRC votes showed a sharp division among stakeholders, with supply (generation and transmission owners) favoring the PJM proposal and load (electric distributors and end-use customers) backing ODEC’s. The same group dynamics played out in earlier votes at the MRC, in which proposals to increase compensation for black start generators failed. (See related story, Members Reject Pay Hike for Black Start Units)

Because clearing prices in incremental auctions (IAs) are usually lower than those in the base residual auction (BRA), participants can profit by selling capacity in the BRA and buying out their commitments in the IAs. PJM and the Market Monitor say such buyouts are suppressing capacity prices and could undermine system reliability.

The MRC had deferred a vote on the issue Nov. 21 after members of the Capacity Senior Task Force were unable to coalesce around any of 11 proposals. (See Arbitrage Fix Returned to Committee.)

The CSTF met five times after that to discuss alternatives, with PJM’s proposal winning 69% support. PJM’s solution would reduce the number of incremental auctions (currently three) and set conditions eliminating the potential to arbitrage between the BRA and IA. The ODEC proposal would also increase the penalties for failing to deliver promised resources, but by less than the PJM package. (See Stakeholders Back PJM on Arbitrage Fix.)

As often happens, however, the seeming support at the lower committee evaporated in the broader sector-weighted voting at the MRC.

Four Votes

PJM’s proposal won only 40% support in the initial vote, with strong support from the generation (67%) and transmission owner (85%) sectors, and opposition from electric distributors (6%), end-use customers (0%) and other suppliers (43%).

In contrast virtually all of the distributors and end users voted for the ODEC proposal, while it was shunned by generation (17%) and transmission (8%). It got 54% overall — well short of the two-thirds needed to recommend it to the Federal Energy Regulatory Commission.

Price Convergence

Several members said the price differential between the BRA and IAs is due in part to PJM’s persistent overforecasts of load. “What’s being done about the forecasts?” asked Dan Griffiths, representing the Consumer Advocates of PJM States (CAPS).

PJM Executive Vice President of Operations Mike Kormos said the load forecast problem is a result of economic performance that has lagged behind the growth rates incorporated into PJM’s load calculations. “The algorithm — if you get the economy right — is quite accurate. The problem is the economy has lagged for five years.”

Susan Bruce, representing the PJM Industrial Customers Coalition, said PJM’s proposal would have “artificially” closed the price gap “at the expense of load.”

Loophole

After the first two votes, discussion then turned to an amendment proposed by PJM to close a loophole regarding capacity acquired through bilateral trades. The amendment would have imposed a “settlement charge” on any party replacing capacity equal to the difference between the BRA and IA clearing prices.

J.P. Morgan’s Bob O’Connell then proposed a vote on PJM’s proposal with a narrowed version of the PJM/IMM amendment that would allow companies with multiple generating assets to replace capacity within their portfolios without paying the charge.

FirstEnergy and Pepco Holdings argued that the amendment was unduly harsh without the exemption. Pepco’s Gloria Godson called it “micromanagement” and “overkill.”

Mystery Number

Mike Borgatti, of Gabel Associates, said the amendment would make it risky to make bilateral trades because the penalty would be a “mystery number” not determined until the IA. Consultant Tom Rutigliano said it would also create unintended consequences for energy efficiency.

Market Monitor Joseph Bowring countered that the PJM proposal “would be meaningless” without the amendment because participants could avoid penalties by buying replacement capacity through bilateral trades rather than incremental auctions.

Even with the exemption, the proposal garnered only 35% support.

In one last attempt, members voted on the PJM proposal and the original amendment, without the exemption introduced by J.P. Morgan.

Ken Jennings, of Duke, said he opposed the exemption. “Because your [forced outage rate] got worse, you shouldn’t be able to profit from that,” he said.

That motion fared worse still, with only 31%.

Next Steps

ODEC’s Ed Tatum said that PJM should attempt to draft language identifying conduct that would justify submitting a participant to FERC enforcement. “Go after the people that we really think are doing the wrong thing,” he said.

“With the changes we’ve seen, I don’t think we need to make any [additional] changes,” Tatum said, referring to limits on the volumes of imports and demand response that will clear in future capacity auctions.

Bowring said Tatum’s proposal was unworkable. “I strongly prefer clear rules rather than after-the-fact enforcement actions,” he said. “Referrals to FERC take a very, very long time. If you have 20 or 30 participants engaging in this kind of behavior it’s not very efficient.”

PJM Executive Vice President for Markets Andy Ott agreed, saying PJM wanted to reinforce the physical nature of capacity commitments. “We don’t want to have to judge intent,” Ott said. “We certainly will be looking at ways to strengthen the physical language.”

The PJM Board voted Thursday to submit the RTO’s proposal, including the amendment to close the bilateral trade loophole, for FERC approval. A filing may come as soon as this week.

March 4, 2014

Manual Change on DR Compensation Rejected; 3 Others OK’d

In a highly unusual move, members Thursday balked at endorsing proposed manual changes governing when Economic demand response qualifies for payment.

The changes to Manual 11 received only 57% in a sector-weighted vote of the Markets and Reliability Committee, with no End Use Customers and less than half of Other Suppliers voting in support.

Most Generation Owners and Transmission Owners voted in support of the changes, which would have specified that demand reductions are eligible for compensation only when they “are not implemented as part of normal operations.”

Ineligible for compensation would be load reductions “that would have occurred without PJM dispatch, or that would have occurred absent PJM energy market compensation.”

No Policy Change

PJM’s Pete Langbein said the manual changes were intended to explain the RTO’s existing interpretation of FERC Order 745. “This is not changing our operative practice,” he said.

Susan Bruce, counsel for the PJM Industrial Customer Coalition, said that additional clarification was needed on PJM’s interpretation of the order, which requires PJM to compensate Economic DR at full Locational Marginal Price when it provides a “net benefit” to the system.

“We have some industrial customers who are really struggling with how to ensure they’re compliant,” she said. “One person’s view of normal operations might be different than another’s.”

Contradicts Order 745

John Webster, of Icetec Energy Services, said the new language would give PJM too much latitude in determining the motives of DR participants and when they should be compensated. He said any revisions should be made through Tariff changes and subject to full stakeholder review.

“From our perspective, it’s contradictory to Order 745,” he said. “There’s no process in place that would allow for that [after-the-fact] analysis.”

Questioned after the meeting, PJM Executive Vice President for Operations Mike Kormos and MRC Secretary Dave Anders said they weren’t sure whether the RTO would use its discretion to add the revisions to the Manual without stakeholder endorsement, or where the issue would go from here.

Manual Changes Approved

Changes to three other manuals won stakeholder endorsements with little discussion:

Manual 7: PJM Protection Standards — These revisions are intended to align the manual with the PJM Relay Subcommittee’s Protective Relaying Philosophy and Design Guidelines. They include changes to section 7 (Line Protection) and section 8 (Substation Transformer Protection).
Manual 40: Training and Certification Requirements — These changes, part of the annual update to meet NERC standards, revise data retention requirements and clarify continued training requirements for transmission operators and initial training requirements for new entities.
Manual 21: Rules and Procedures for Determination of Generating Capability — These changes strengthen the rules for summer verification testing of steam generation units and provide a transition mechanism for those who haven’t been providing appropriate testing results to PJM. (See Transition Period OKd for Seasonal Verification Rules.)