Page 1625 – RTO Insider

August 26, 2014June 15, 2023

Duke, ECP Deals Boost PJM Rank

By Ted Caddell

Dynegy, which emerged from bankruptcy just two years ago, announced Friday it will nearly double its capacity with the purchase of about 12,400 MW of generation from Duke Energy and private equity firm Energy Capital Partners.

If approved by regulators, the deal would rank Dynegy just behind Calpine, the third-largest competitive generator in the U.S.

Dynegy would gain about 9,000 MW in PJM, boosting it to more than 10,700 MW and eighth in generation share in the RTO.

The $2.8 billion Duke agreement includes 11 generating units in the Midwest and Duke Energy Retail, Duke’s competitive retail energy business in Ohio, Pennsylvania and Michigan — adding to Dynegy’s existing retail business in Illinois. The $3.45 billion deal with Energy Capital Partners is for 10 units in the Midwest and New England.

Growth in New England

In addition to making it a major player in PJM, the transaction will give Dynegy a larger foothold in ISO-NE.

Dynegy could briefly dislodge Exelon from the top of the New England generation market share rankings as a result of its ECP acquisition and Calpine’s announcement yesterday that it will buy Exelon’s Fore River Generating Station, an 809-MW combined-cycle plant near Boston, for $530 million. (See related story, Dynegy Becomes New England Player Overnight.)

Dynegy would drop to fifth after the scheduled 2017 retirement of ECP’s 1,510-MW Brayton Point coal generator.

“The addition of these portfolios transforms Dynegy by adding considerable scale in the PJM and New England markets,” Dynegy President and CEO Robert Flexon said. Dynegy said it expects the deals to close by the end of the first quarter of 2015.

Investors reacted favorably, with Dynegy’s shares jumping 18% on the news before settling at $32.58 Monday, an 8% gain.

Merchant Generation, Retail Sales

Dynegy currently has about 13,200 MW of generation: 7,042 in MISO; almost 2,700 in CAISO; 1,780 in PJM; 1,064 in NYISO; and 540 in ISO-NE.

Dynegy is betting on two sectors — merchant generation and retail sales — that other players have been exiting or de-emphasizing.

Duke signaled its intention to pull out of the merchant generation business in February, days after the Public Utilities Commission of Ohio refused the company’s request to bill regulated customers $729 million to make up for a shortfall between its plant operating costs and plunging wholesale power prices.

PPL announced in June it would spin off its generation unit in a deal with Riverstone Holdings, leaving it with a pure rate-regulated business model.

Exelon agreed in May to buy Pepco Holdings Inc. for $6.83 billion, seeking to increase its regulated rate base.

Duke is not alone in souring on the competitive retail business. Dominion Resources agreed in March to sell its business serving 600,000 retail customers to NRG Energy. FirstEnergy Solutions said this month it will stop pursuing sales to residential and small and mid-size commercial customers.

Dynegy, however, sees retail sales as a “natural hedge for our generation,” spokeswoman Katie Sullivan said.

Back from Bankruptcy

Founded in 1984 as a gas trading company, Dynegy has had a turbulent history. It survived several Enron-era scandals, near-bankruptcy in 2002 and attempted takeovers in 2010.

In its high-flying days, it owned plants in a dozen states and six foreign countries. When it emerged from bankruptcy in October 2012, it was down to 16 power plants in six states.

The company began to rebuild its merchant fleet last year, buying St. Louis-based Ameren Corp.’s five coal-fired plants in Illinois.

Dynegy is betting on economies of scale with the Duke and ECP acquisition. It expects to realize fuel cost and maintenance savings of $40 million and operational management savings of $200 million. It says these deals will drop its overhead cost 35%, from $1.67/MWh to $1.10/MWh.

The deal will also allow it to take advantage of a $3.2 billion net-operating-loss carry-forward that it says will yield $480 million in tax savings on future earnings.

Its free cash flow yield on the new assets will be 36%, the company said, refilling its coffers for perhaps more acquisitions in the future.

The company will finance the acquisitions with $5 billion in unsecured notes and $1.25 billion in equity and equity-linked securities, including $200 million in common stock issued to ECP.

Bullish on PJM, New England

Dynegy said it is bullish on both the PJM and ISO-NE markets. Plant retirements will translate into tighter reserve margins and higher energy and capacity prices, it says, particularly in New England.

“New England is not getting any new builds,” Flexon said in a conference call with stock analysts Friday. Retiring Brayton, as the current owners had planned, “puts pressure on that marketplace also.”

Capacity payments represent 11% of Dynegy’s current gross margins. With the new acquisitions, capacity payments will represent 25%, as it more than quintuples its generation in PJM and ISO-NE.

MISO’s share of Dynegy’s total generation will fall to 29% from 53% as a result of the expansion in PJM and New England. But Flexon was also optimistic about the company’s prospects in the Midwest, saying 2015 through 2017 “should be a really peak time for the MISO marketplace” due to plant retirements.

Fuel Diversity

Once Brayton Point is closed, Dynegy will have reduced the share of coal-fired generation in its fleet to 45% from 53%. The company said the 3,800 MW of coal-fired plants it is acquiring, excluding Brayton Point, are all “environmentally compliant.”

About 7,000 MW of the acquisition are natural gas-fired plants, including 5,000 MW of modern, low-heat-rate, high-capacity-factor combined-cycle plants.

Julien Dumoulin-Smith, a utility analyst at UBS Securities, said the deals are positive for Dynegy’s long-term growth and will provide protection from a takeover by another company.

“The transaction propels Dynegy to among the largest IPPs in the industry, likely no longer a take-out target,” he said. “Strategically, the deal adds substantial diversification to a portfolio both overly levered to the MISO market, as well as some further diversification from coal.”

Dumoulin-Smith didn’t see much problem getting regulatory approval for the deals. “As for execution of the transaction, we do not anticipate any significant hurdles, with only very limited market overlap across any of the contemplated portfolios.”

William Opalka contributed to this article.

August 26, 2014June 15, 2023

PJM Members Split over MRC/MC Meeting Site

PJM stakeholders often divide into factions, but the split that emerged in a Members Committee discussion Thursday had nothing to do with long-running battles over demand response, capacity market rules or uplift. Rather, the issue was where these battles should be fought.

For the last two months, Members and Markets and Reliability committee meetings normally held at the Chase Center in Wilmington, Del., were relocated to PJM’s Conference and Training Center in Valley Forge, Pa., to avoid traffic tie-ups resulting from repairs to a highway bridge in Wilmington. With the bridge now reopened, the two senior committees are scheduled to return to Wilmington in September.

But some stakeholders — and PJM staff — would like to abandon Wilmington and hold the meetings in Valley Forge, where lower-level meetings have been held since the CTC was completed in July 2012.

Supporters of the CTC location cited its proximity to PJM staff, only some of whom regularly attend the MRC/MC meetings. Chief Financial Officer Suzanne Daugherty said PJM spends about $150,000 annually to hold meetings at the Chase Center, not including staffers’ mileage payments and travel time.

Others, particularly those whose companies are based south of Philadelphia, said Wilmington was preferable because of its location near an Amtrak station. Valley Forge lacks mass transit and requires those outside the Philadelphia area to make a long drive or rent a car after flying or taking a train into the city.

Ed Tatum of Old Dominion Electric Cooperative said the trip to Valley Forge can take him at least five hours by car. Moving all meetings to Valley Forge, he said, could result in “a cottage industry of people who live in this [Philadelphia] area and only get to the home office once a month.”

Tatum said any decision should consider not only PJM’s costs but members’ travel costs.

Lisa Moerner of Dominion Resources said “there is no good option to get to Valley Forge” from her Richmond, Va., base. “Wilmington is much easier for those coming from the south,” she said.

Marji Phillips of Direct Energy suggested using the Cira Centre, next door to Philadelphia’s 30th Street Station.

PJM officials said they would explore their options, including one suggestion that it offer shuttle buses to transport members to the CTC from a nearby train station.

August 26, 2014

PJM MRC/MC Briefs

Markets and Reliability Committee

The Markets and Reliability Committee approved the following with little debate or discussion on Thursday.

Manual Changes Approved

Manual 12: Balancing Operations. Updates Section 4.5, “Qualifying Regulating Resources,” for clarity, accuracy and consistency, including a description of current regulation testing procedures; consolidates “PJM Actions” from previous subsections into Section 4.5.
Manual 14B: PJM Region Transmission Planning Process. Adds language describing easily resolved constraints for Capacity Emergency Transfer Limits (CETL) to match that in the Tariff. (See MRC / MC Approvals.)
Manual 11: Energy & Ancillary Services Market Operations. Conforming revisions, adding references to “pre-emergency” demand response. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

Supplemental Transmission Projects

The committee approved Operating Agreement revisions defining supplemental transmission projects, as recommended by the Regional Planning Process Senior Task Force. (See PJM’s `To Do’ List.)

Settlement, Credit Changes

Members OK’d manual and Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes are intended to address problems with reporting output for non-utility generators. (See PJM MIC OKs Settlement, Credit Changes.)

The committee also approved manual and Reliability Assurance Agreement changes recommended by the Market Settlements Subcommittee allowing EDCs to submit corrections to Peak Load Contribution and Network Service Peak Load assignments until noon on the next business day. The changes are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)

Members Committee

The Members Committee approved a “back stop” mechanism for acquiring black start services through transmission providers when PJM solicitations fail to obtain service for a zone. Members also approved minor Tariff and manual changes relating to the compensation of black start units. Both sets of changes were approved by the MRC July 31. (See MRC Briefs.)

August 26, 2014June 15, 2023

FERC: PJM Uplift Ranks High Among RTOs, ISOs

PJM has consistently had among the highest uplift rates among RTOs and ISOs, according to a Federal Energy Regulatory Commission report released last week.

The FERC staff report found that PJM’s uplift ranked second among organized markets from 2009 to 2013, with charges increasing from about $0.50/MWh to more than $1/MWh over that period. Only NYISO was consistently higher.

The report also found that:

Some resources and regions, such as PJM’s Dominion-Virginia and Delmarva zones, receive a disproportionate volume of uplift payments. PJM had among the highest concentrations of uplift payments, with 19 generating plants receiving more than $10 million and 33 receiving at least $5 million in 2013, the 33 representing 82% of total uplift for the year.
Uplift payments are closely related to differences between coal and natural gas prices and divergences between day-ahead and real-time prices.
The volatility of uplift costs varies across RTOs and ISOs. It has risen in three of the five markets studied, including PJM.
A lack of transparency on the location of uplift credits and the reasons they are incurred are inhibiting market participants from making investments that could reduce the costs.

Sept. 8 Workshop

The report was intended to frame issues for discussion at FERC’s Sept. 8 workshop on uplift payments in energy and ancillary service markets (AD14-14).

FERC had said in June that it would convene a series of workshops to consider rule changes regarding uplift, price caps and other issues affecting price formation in PJM and other RTOs and ISOs.

The commission said its inquiry was prompted by comments made at recent technical conferences on capacity markets and the grid’s response to the recent severe winter. The workshops will consider ways to address limitations in RTO market software that prevent RTOs from modeling all system parameters, such as voltage constraints and generator operating constraints. (See FERC to Tackle RTO Uplift, Price Formation.)

Among those scheduled to speak at the conference are PJM Market Monitor Joe Bowring; Stu Bresler, PJM vice president of market operations; Jason Cox of Dynegy; Wesley Allen, representing the Financial Marketers Coalition; Judith Judson, representing the Energy Storage Association; Harry Singh of J. Aron & Co.; and Bob Weishaar of the PJM Industrial Customer Coalition.

Uplift Tab: $5.5 Billion

The report said uplift in PJM, NYISO, ISO-NE, CAISO and MISO totaled $5.5 billion in the 2009-13 period.

While the report noted the charges were a small fraction of energy costs, it said “a failure to make the causes transparent and to price them into the energy and ancillary services markets can undermine the effectiveness of price signals and efficient system utilization and mute investment signals. Volatile uplift charges may also create financial uncertainty for customers, depress liquidity and reduce market efficiency.”

PJM market participants have complained that uplift costs create unnecessary risk because they are unpredictable and not hedgeable.

The persistence of uplift in regions such as the Delmarva Peninsula “may indicate that market pricing is consistently failing to fully capture costs associated with committing and dispatching those resources or the existence of market work-arounds,” the report added. It noted that one PJM generating plant received at least $60 million in uplift annually in four of the five years studied.

The report said added transparency would aid development of solutions to reduce uplift. “For instance, knowing that the vast majority of uplift in a particular import-constrained zone is related to the provision of reactive power could make clear to market participants that the zone is reactive power deficient. This could lead to proposals to address reactive power compensation and potentially send a price signal to enhance reactive power capability. On the other hand, knowing that a majority of uplift in a particular zone is related to local ‘reliability’ could suggest that the model is not incorporating certain constraints or the operators are conservatively committing units to address generic concerns,” the report said.

PJM’s Market Monitor has called on PJM to identify the generators receiving uplift, but PJM officials said they are prevented from doing so by confidentiality rules and would require a FERC order giving them approval. The Monitor says the prohibition against disclosure of market-sensitive information should not apply to uplift. (See PJM Won’t Name Uplift Recipients.)

August 26, 2014

ATSI Black River Interface to Take Effect Sept. 1

PJM will create a temporary pricing interface in the ATSI Black River area as a result of a transmission outage. The interface will capture in LMPs operator actions taken to relieve thermal or voltage problems resulting from high loads.

Most of the load buses defining the BLKRIVER closed-circle interface are in the ATSI transmission zone. It will be modeled in the day-ahead market if operators know they will be deploying sub-zonal load management before market deadlines. It will not be modeled in Financial Transmission Rights markets.

The interface will be effective Sept. 1 through Oct. 31, 2014, when the transmission outage is scheduled to be completed.

August 26, 2014June 15, 2023

Monitor: Resist Subsidies, Don’t Retreat from Markets

PJM’s Market Monitor made no new recommendations in its second-quarter report, but that doesn’t mean Joe Bowring didn’t have anything to say.

Instead, the Monitor used his newest State of the Market report to repeat longstanding recommendations and warn stakeholders not to overreact to the winter’s extreme weather, which sent prices skyward and brought the RTO uncomfortably close to having to cut loads.

“Particularly in times of stress on markets and when some flaws in markets are revealed, non-market solutions may appear attractive. Top-down, integrated resource planning approaches are tempting because it is easy to think that experts know exactly the right mix and location of generation resources,” the Monitor wrote.

But the Monitor said the lure of integrated planning, cost-of-service rates and subsidies for favored generation technologies should be resisted because “the market paradigm and the non-market paradigm are mutually exclusive.”

“Once the decision is made that market outcomes must be fundamentally modified, it will be virtually impossible to return to markets.”

The Monitor said criticism of the performance of PJM’s energy and capacity markets is legitimate. But he added, “Before market outcomes are rejected in favor of non-market choices, markets should be permitted to work.”

Capacity Prices Suppressed

The report repeats previous calls to eliminate limited demand response and the 2.5% demand offset from the capacity auction, saying the two combined to reduce revenues in the 2017/18 Base Residual Auction by $3.4 billion, or 31%.

“Premature and uneconomic retirements and the failure to make economic investments in new entry are both the results [of the price suppression]. … The most fundamental required change to the capacity market design is the enforcement of a consistent definition of a capacity resource so that all capacity resources are full substitutes for one another.”

The report said the 22% forced outage rate in early January was evidence that current capacity market rules have insufficient incentives and penalties.

“At present, only half of capacity market revenues are at risk for failure to perform on high demand days. Gas-fired units with a single fuel are exempt from any capacity market revenue impact that results from lack of fuel outages on high demand days. … An increase in capacity market prices must be accompanied by a strengthening of capacity market incentives so that customers can be assured of getting what they pay for.” (See related story, Reaction Muted as PJM Pitches New Capacity Product.)

Below are some statistical highlights from the 442-page report.

Prices, Revenues

The load-weighted average LMP was 84% higher in the first six months of 2014 than the first half of 2013 ($69.92/MWh vs. $37.96/MWh). High fuel prices played a large role in the increase. Had fuel prices been equal to the first six months of 2013, LMPs would have risen only 52% to $57.71/MWh.

All technology types received big increases in net revenues due to the extraordinary prices early in the year: combustion turbine (+730%); combined-cycle (+202%); coal (+338%); nuclear (+96%); wind (+32%); and solar (+14%). All figures assume that these are new plants.

Market Power

Baseload generation had an average Herfindahl-Hirschman Index (HHI) of 1,174 in the first two quarters, making it moderately concentrated under the Federal Energy Regulatory Commission’s Merger Policy Statement.

Intermediate generation averaged 1,719, at the high end of moderately concentrated, but rose as high as 5,693. FERC considers an HHI above 1,800 as highly concentrated (equivalent to between five and six firms with equal market shares).

Peakers averaged a highly-concentrated 6,119 and rose as high as 10,000, similar to patterns seen in 2013.

Nevertheless, market power mitigation ensured that energy, capacity and regulation markets produced competitive results, the Monitor said.

Marginal Units

Coal (47.6%) and gas (41%) units were marginal in all but about 11% of real-time hours in the first six months. Oil set prices for 5.7% of hours while wind units were responsible for about 5%.

In all but 1.4% of wind’s marginal hours, the marginal price was at (23%) or below (76%) $0/MWh.

August 21, 2014June 15, 2023

PJM: New Capacity Product Needed for Reliability

PJM officials yesterday proposed sweeping changes to the capacity market to address concerns over the poor performance of generators in early January, when as much as 22% of PJM’s generating fleet was unable to run.

The proposed changes are certain to be the subject of vigorous debate over its cost and impact on generators and demand response providers. The first discussion will come at a meeting Friday of the “Capacity Performance” initiative. (See PJM to Hike Penalties, Incentives to Improve Winter Reliability.)

The centerpiece of the proposal is the addition of a new “Capacity Performance” product that would supplement existing Annual Capacity, Extended Summer and Limited Demand Response offerings.

The new product would include generation, DR and energy efficiency providers that can guarantee their availability during hot and cold weather alerts and maximum emergency generation alerts. The resources would need to demonstrate they can produce their committed installed capacity for 16 hours for each of three consecutive days.

Fuel Access

For generators, that would require access to fuel and no long notification or start times.

Gas generators would have to show they have dual-fuel capability or have secure gas supplies through a combination of firm delivery service or access to storage. Coal generators would have to demonstrate that they have taken steps to ensure their coal piles and conveyors will not freeze.

All eligible generators would have to demonstrate sufficient weatherization and operations and maintenance procedures to ensure that the unit can operate “through extreme hot or cold weather conditions.”

Penalties would be assessed for every hour that energy is not delivered, but the penalty could be offset by energy produced by a non-capacity resource in the generation owner’s portfolio.

Annual DR providers would have to be available 24 hours a day all year and ensure reductions for 16 peak hours over three consecutive days. “This requirement effectively means DR must be present summer and winter,” PJM said.

2015/16 Concern

PJM said its action was prompted by concern that a 22% outage rate in the winter of 2015/2016, “coupled with extremely cold temperatures and expected coal retirements, would likely prevent PJM from meeting its peak load requirements.”

Officials said the changes would have no immediate impact on the RTO’s installed reserve margin (IRM) calculation because “existing IRM calculations already assume higher capacity performance than is occurring, meaning that the new product should produce performance that already is factored in to the IRM calculation.”

The existing annual capacity product would be renamed “base capacity.”

PJM would establish maximum product quantities for the Limited DR, Extended Summer and Base Capacity products based on their combined reliability impact.

“This method will calculate the amount of Capacity Performance resources that can be displaced by the sum of Limited DR, Extended Summer and Base Capacity products until there is a 10 percent increase in the [loss-of-load expectation],” PJM said. “By applying such a method, PJM will allow resources with availability limitations to clear in RPM auctions only up to maximum quantities which do not significantly increase reliability risk.”

Cost Allocation

The changes would take effect for the May 2015 Base Residual Auction (BRA), with a transitional mechanism to address reliability requirements for delivery years 2015/16 through 2017/18.

PJM offered two options for assigning costs under the new construct.

One would continue current rules, which assign capacity costs to load-serving entities based on their daily unforced capacity obligation. This would recognize that while the changes are primarily intended to improve winter performance the “critical period” penalties should also improve summer reliability.

An alternative would be to allocate the additional costs of the Capacity Performance product based on zonal winter peak load forecasts.

[Editor’s Note: RTO Insider will have a full report on the PJM proposal, and stakeholders’ reactions to it, in Tuesday’s edition.]

August 19, 2014June 15, 2023

MRC/MC Preview

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 Valley Forge covering the discussions and votes (note change from normal location in Wilmington). See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM MANUALS (9:10-9:25)

The committee will be asked to endorse the following manual changes:

A. Manual 12: Balancing Operations. Updates Section 4.5, “Qualifying Regulating Resources,” for clarity, accuracy and consistency, including a description of current regulation testing procedures; consolidates “PJM Actions” from previous subsections into Section 4.5.

B. Manual 14B: PJM Region Transmission Planning Process. Adds language that describes Capacity Emergency Transfer Limit (CETL) easily resolved constraints to match that in the Tariff. (See MRC / MC Approvals.)

C. Manual 11: Energy & Ancillary Services Market Operations. Conforming revisions, adding references to “pre-emergency” demand response. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

3. RPM TRIENNIAL REVIEW (9:25-10:30)

The committee will be asked to approve changes to parameters used in capacity auctions: the cost of new entry (CONE), the energy and ancillary services (E&AS) offset and the variable resource requirement (VRR) curve. The changes, which were considered by the Capacity Senior Task Force in PJM’s triennial review, would be implemented for the 2015 Base Residual Auction (BRA).

The packages of proposed changes brought to a vote will be based on the results of a formal CSTF poll, which will be completed before the MRC meeting.

In informal polling at the CSTF, only two of nine packages received more than 50% support: Public Service Enterprise Group’s package B and Dayton Power and Light’s package I (both 57% in favor). The two packages are identical in seven of 11 attributes, differing only on calculation of gross CONE, net E&AS offset, VRR shape (system) and net CONE method (RTO). (See table.)

In the informal polling, a majority also favored increasing the weighted average cost of capital in calculating gross CONE, with 57% expressing support and another 13% saying they would consider it, while 31% were firmly in opposition.

Changes to the levelization method found little support, with 71% saying they support the status quo. Changes to the net E&AS offset also proved unpopular, with only 40% wanting to abandon the status quo.

A majority — 59% to 63% — favored changing the VRR curve from the current concave shape to a convex shape.

The Maryland Public Service Commission sent PJM a letter detailing its opposition to three changes to the VRR curve proposed by the RTO: moving the curve’s “point a” to the right to increase capacity price levels sooner if reserve levels are threatened; changing to a convex shape from the current concave curve; and moving the entire curve an additional 1% to the right.

The PSC said PJM’s proposal is based on unduly conservative assumptions and would be expensive for consumers. Had the changes been in place for the last three BRAs, total capacity spending would have increased by $1 billion to $1.7 billion, a PJM simulation estimated.

BRAs are held three years before the delivery year, with the RTO able to acquire additional capacity in interim auctions. The PSC said this structure “provides an adequate time period for PJM and government to react to” any shortfalls. The PSC also said an analysis by The Brattle Group for PJM ignores this flexibility, “thus severely overstating the risk of inadequate generation, which it asserts as justification for PJM’s modified VRR curve.”

4. REGIONAL PLANNING PROCESS SENIOR TASK FORCE (RPPTF) (10:30-10:40)

The committee will be asked to approve Operating Agreement revisions defining supplemental transmission projects. (See PJM’s `To Do’ List.)

5. POWER METER AND IN-SCHEDULE DATA SUBMITTAL DEADLINES (10:40-10:50)

Members will consider proposed manual and Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data to address problems with reporting output for non-utility generators. (See PJM MIC OKs Settlement, Credit Changes.)

6. CAPACITY CONTRIBUTION RECONCILIATION (10:50-11:00)

The committee will vote on proposed manual and Reliability Assurance Agreement changes recommended by the Market Settlements Subcommittee that would allow EDCs to submit corrections to Peak Load Contribution and Network Service Peak Load assignments until noon on the next business day. The changes are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)

7. FTR/ARR SENIOR TASK FORCE (FTRSTF) PROBLEM STATEMENT, ISSUE CHARGE AND CHARTER (11:00-11:30)

Members will discuss, and may vote on, proposed updates to the FTRSTF problem statement, issue charge and charter. The task force was formed to evaluate the causes for Financial Transmission Rights underfunding and determine whether enhancements can be made to the current FTR and Auction Revenue Rights processes to improve FTR funding levels.

Members Committee

2. CONSENT AGENDA (1:20-1:25)

B. The committee will be asked to approve a “back stop” mechanism for acquiring black start services through transmission providers when PJM solicitations fail to obtain service for a zone. Members will also vote on minor Tariff and manual changes relating to the compensation of black start units. Both sets of changes were approved by the MRC July 31. (See MRC Briefs.)

3. RPM TRIENNIAL REVIEW (1:25-2:30)

See MRC item #3 above.

August 15, 2014

FERC Order 1000 Upheld — UPDATE

By Rich Heidorn Jr.

WASHINGTON — A federal appellate court Friday upheld the Federal Energy Regulatory Commission’s landmark Order 1000, rejecting arguments from those who claimed FERC exceeded its authority and those who complained it didn’t go far enough.

A three-judge panel for the D.C. Circuit Court of Appeals unanimously rejected challenges to FERC’s jurisdiction and claims that allowing competition in transmission development will harm reliability, saying it found them “unpersuasive.”

The 97-page order by Judges Thomas B. Griffith, Nina Pillard and Ann Wilson Rogers was a complete vindication for the commission and a shutout for challengers.

The ruling responded to challenges from 45 petitioners and considered input from 16 intervenors. The main threat to the order came from challengers in the Southeast and West who alleged the commission exceeded its authority under the Federal Power Act in requiring that public utility transmission providers participate in regional transmission planning, and in eliminating incumbent transmission providers’ monopoly on building and running transmission.

The court found that FERC had authority under Section 206 of the FPA to require:

Transmission providers participate in a regional planning process;
Removal of federal rights-of-first-refusal provisions “upon determining they were unjust and unreasonable practices affecting rates;” and
The allocation of the costs of new transmission facilities based on forecasted benefits.

In addition, the court found that:

There was “substantial evidence of a theoretical threat to support adoption of the reforms” in Order 1000;
FERC “reasonably determined that regional planning must include consideration of transmission needs driven by public-policy requirements;” and
FERC “reasonably relied upon the reciprocity condition to encourage non-public utility transmission providers to participate in a regional planning process.”

FERC Chairman Cheryl LaFleur said she was pleased with the ruling. “Our nation needs substantial investment in transmission infrastructure to adapt to changes in its resource mix and environmental policies,” she said in a statement. “Order No. 1000 is critical to the commission’s efforts to support efficient, competitive and cost-effective transmission.”

Order 1000, issued in July 2011, changed the process for planning and paying for new regional and interregional transmission lines. It also allows independent developers to compete with traditional utilities in building new lines.

The ruling was not a surprise for those who attended oral arguments in the case in March. The judges questioned attorneys seeking to overturn the order far more aggressively — and interrupted them far more often — than they did when responding to FERC’s attorneys. (See Appellate Court Skeptical of Order 1000 Challengers.)

Below is a summary of the issues raised by the challengers and the court’s response.

MANDATORY REGIONAL PLANNING

Petitioners led by the South Carolina Public Service Authority alleged the commission lacks authority to mandate transmission planning because the FPA only allows FERC “to regulate existing voluntary commercial relationships.” As precedent, the petitioners cited the D.C. Circuit’s 2004 ruling that invalidated FERC’s attempt to change the composition of the California ISO board of directors.

The court said Order 1000 was justified by the commission’s concern that a lack of competition would lead to higher costs for new transmission needed to address environmental, economic and reliability concerns.

“Reforming the practices of failing to engage in regional planning and ex ante cost allocation for development of new regional transmission facilities is not the kind of interpretive ‘leap’ that concerned the court in CAISO but rather involves a core reason underlying Congress’ instruction in Section 206” to remedy unjust or unreasonable rates and practices, the court said.

Petitioners embraced a “false premise” that commission-mandated transmission planning is new, the court said, citing prior commission Orders 890 and 888.

The judges also said the challengers mischaracterized “mandated transmission planning as mandating binding commercial relationships.”

The allegation that Order 1000 interferes with state regulation of planning “poses a closer question,” the court acknowledged. “But while petitioners’ argument is not without force, relevant precedent” supported FERC, the court ruled, saying “the commission possesses greater authority over electricity transmission than it does over sales.”

‘THEORETICAL THREAT’ BASIS FOR ORDER 1000

Opponents said the commission failed to provide evidence needed to justify the rule and that it was improperly seeking to change already just and reasonable planning practices.

The commission justified Order 1000 on the “theoretical threat” that “the narrow focus of current planning requirements and shortcomings of current cost allocation practices create an environment that fails to promote the more efficient and cost-effective development of new transmission facilities.”

The court said the challengers “misconceived the nature of the commission’s evidentiary burden.”

It backed FERC’s conclusion that Order 890 was insufficient to ensure just and reasonable rates because it did not require transmission providers to consider regional transmission alternatives that might be more cost effective than solutions identified in local transmission plans.

The challengers’ contention that FERC had failed to recognize that electric transmission is a natural monopoly “misconceives the basis for the competitive benefits predicted by the commission,” the court said. It cited antitrust literature that concludes that competition for a natural monopoly can be beneficial.

“Even in a naturally monopolistic market, the threat of competitive entry (e.g., through competitive bidding) will lead firms to lower their costs, which thereby generally lowers cost-based utility rates,” the court said.

REMOVAL OF FEDERAL RIGHTS OF FIRST REFUSAL

Public Service Electric and Gas and other incumbent transmission owners contested Order 1000’s requirement that utilities eliminate from their tariffs and agreements certain rights of first refusal (ROFR). ROFRs give incumbents the option to construct any new transmission facilities in their service territory, even those proposed by third parties.

Continuing ROFRs would discourage non-incumbents from identifying cost-efficient projects, resulting in the development of transmission facilities “at a higher cost than necessary,” the commission said.

The challengers said the commission should be required to provide evidence that existing ROFRs were adversely affecting rates. Such evidence did not exist, they contended, because awarding projects to non-incumbents would mean the loss of economies of scale and scope.

The incumbents also contended that eliminating ROFRs would undermine reliability because non-incumbents might lack the financial backing or technical expertise to complete essential projects on time.

The court said FERC properly addressed reliability concerns by continuing ROFRs for projects that would be located entirely within a utility’s service territory and would not be subject to regional cost allocation.

The challengers also said there was only a tenuous relationship between the incumbents’ monopolies and rates. As a result, they contended, FERC lacked authority to remove them under Section 206, which is limited to practices “affecting” a rate.

The court again made a distinction between Order 1000 and the CAISO case cited by opponents.

“The relationship between rights of first refusal and rates is far more direct than the relationship between corporate governance and rates. Nothing suggests that replacing the members of a board will necessarily affect rates. … The challenged orders here provide what was lacking in CAISO: an economic principle that directly ties the practice the commission sought to regulate to rates.”

The court also rejected arguments that differences between the FPA and the Natural Gas Act (NGA) undercut FERC’s jurisdiction.

While the NGA contains a provision analogous to FPA Section 206 that gives the commission authority to regulate practices affecting rates, it also contains a separate provision expressly authorizing the commission to regulate the construction of natural gas pipelines. The FPA does not include a similar provision regarding construction of electric transmission.

The court said it found the petitioners’ argument “unconvincing,” concluding that Section 206 does not “unambiguously” limit the commission’s authority.

“We think that the commission’s reading of Section 206 is reasonable. Petitioners give us no persuasive reason to think otherwise,” the court ruled. “…The challenged orders take great pains to avoid intrusion on the traditional role of the states.”

The court also rejected complaints that the ROFR removal violates the Mobile-Sierra doctrine, which presumes that freely negotiated wholesale-energy contracts are just and reasonable unless found to seriously harm the public interest.

Some petitioners argued that the commission unlawfully deprived them of their rights of first refusal without first making the finding required to rebut the Mobile-Sierra presumption. The court said FERC had committed to hearing the petitioners’ Mobile-Sierra arguments when it reviews the new tariffs utilities must file to comply with Order 1000.

COST ALLOCATION

Order 1000’s cost allocation rules came under fire from both sides, with some challengers accusing FERC of overstepping its authority, and ITC Holdings and others urging stronger measures.

The court said the commission had used a “light touch” in requiring that the costs of new transmission are allocated to beneficiaries while leaving the details to transmission providers.

ITC contended Order 1000 is inconsistent with the commission’s cost causation principle because it required interregional transmission lines to be approved by each transmission planning region in which the line is located.

The commission acknowledged that its rule “may lead to some beneficiaries of transmission facilities escaping cost responsibility because they are not located in the same transmission planning region as the transmission facility.”

FERC said it went this route because “allowing one region to allocate costs unilaterally to entities in another region would impose too heavy a burden on stakeholders to actively monitor transmission planning processes in numerous other regions.”

The court said it would not second guess the commission’s compromise. “The commission’s balancing of the competing goals of reducing monitoring burdens and adopting policies that ensure that cost allocation maximally reflects cost causation is wholly reasonable under the deferential review we accord in rate-related matters.”

PUBLIC POLICY REQUIREMENT

FERC faced three challenges to its requirement that transmission planners account for federal, state and local laws and regulations, such as renewable portfolio standards.

One faction said FERC exceeded its authority while a second said FERC should have required transmission planners to consider the needs of load serving entities. A third said the rule was too vague, leaving transmission providers unable to determine what is required of them.

“None [of the arguments] is persuasive,” the court ruled, saying they were based on misunderstandings of the rule.

The court said those challenging FERC’s jurisdiction “seem to argue that the commission can only exercise authority to promote goals specified in the FPA and that the public-policy mandate cannot be justified with respect to any of those goals.”

“This argument misunderstands the nature of the mandate. It does not promote any particular public policy or even the public welfare generally. The mandate simply recognizes that state and federal policies might affect the transmission market and directs transmission providers to consider that impact in their planning decisions.”

RECIPROCITY

The commission was also attacked from two sides for its requirement that non-public utility transmission providers that want access to a public utility’s transmission lines must participate in transmission planning and cost allocation. Non-public utilities, such as municipal utilities and rural cooperatives, are not subject to Section 206 of the FPA, and thus not directly covered by Order 1000.

One group of challengers said the commission lacked justification for expanding the reciprocity conditions of Orders 890 and 888 to include planning and cost allocation. The Edison Electric Institute said the commission should have mandated the participation of non-public utilities in planning and cost allocation.

“Both contentions miss the mark,” the court said, saying the commission’s conditional requirement for non-public utilities had “a reasoned and adequate basis.”

The reciprocity condition in Order 1000 “is fundamentally the same [as that required by Orders 888 and 890]. … The current orders simply apply that principle to transmission planning and cost allocation,” the court continued.

“The commission provided an adequate justification for that change — namely, that non-public utilities that take service from public utilities will benefit greatly from the reforms announced in the Final Rule, because ‘a well-planned grid is more reliable and provides more available, less congested paths for the transmission of electric power in interstate commerce.’”

August 12, 2014

Combined-Cycle Model’s Cost, Benefit Uncertain

By Rich Heidorn Jr. and William Opalka

PJM is hesitating on plans to introduce more sophisticated modeling of combined-cycle plants because of an inability to quantify potential savings and reports of escalating prices.

Currently, a combined-cycle plant must be entered into eMKT as either a combustion turbine or steam unit. Neither option captures its true capabilities, which can vary greatly based on unit configurations and use of duct burners.

PJM has been considering spending about $1 million on software from Alstom that it believes will give it more flexibility. But PJM’s Tom Hauske told the Operating Committee that PJM and the Market Monitor have been unable to quantify savings to justify the software purchase.

Joel Luna of Monitoring Analytics said the model would result in more efficient use of combined cycles with multiple configurations, allowing PJM to decide the optimal configuration depending on expected load and system conditions. It also would make the most of the peaking segment of PJM’s combined-cycle plants by allowing operators to make better decisions about how to schedule such units based on their technical parameters.

Luna said the result will be greater operational flexibility, more accurate pricing and reductions in uplift and production costs.

In 2013, there were 291 instances in which operators ran a combined-cycle plant at its minimum load for its entire operating interval — suggesting inefficient use of PJM resources.

If better software could reduce those start costs by half, Hauske said, it would produce savings of $2.4 million. “That’s not a firm number,” he cautioned.

“We have reasonable qualitative reasons [for making the change],” said Mike Bryson, executive director of system operations. “We’re a little concerned that we don’t have great quantitative stuff.”

“If we can’t quantify the savings, are we going to spend $1 million?” Luna asked stakeholders.

“A million would be worth spending,” answered Dave Pratzon of GT Power Group, which represents generators. Pratzon said he was concerned by reports that the Southwest Power Pool has reportedly put their purchase of the Alstom software on hold because of costs rising as high as $4 million.

But he added, “If we thought we had a good solution for $1 million, I think it would be worth doing.”

Duke’s Ken Jennings agreed, saying less efficient modeling inhibits the ability to regulate system frequency.

SPP spokesman Tom Kleckner said SPP had planned to implement the software in November 2015, but there were concerns about the potential cost, which led the board two weeks ago to ask for further study. “The board wanted to have a more detailed cost-benefit analysis,” he said. SPP declined to discuss specific cost figures.

Hauske said PJM is unaware of any region using the Alstom software, although he said MISO is considering a June 2015 implementation.

A MISO spokeswoman said yesterday that the software program is under review but denied plans for a 2015 deployment.

“If the evaluation demonstrates positive prospects, MISO will work with stakeholders to develop a detailed design and implementation plan,” MISO said in a statement. “At this stage, we haven’t purchased any production level product, and there is no current plan of implementing this enhancement in 2015.”

Bryson noted that PJM’s Aug. 1 white paper stressed the need for flexibility. “That’s another reason to keep it on the table,” he said.