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December 8, 2025

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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.

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Monitor: Resist Subsidies, Don’t Retreat from Markets

monitorPJM’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

monitorBaseload 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.

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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.)

Method for Determining Maximum Quantities for Limited Capacity Products (Source: PJM Interconnection LLC)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.]

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MRC/MC Preview

pjmBelow 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.

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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.’”

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PJM Backs Off on Regulation Market Fix

regulationPJM dropped a proposal to consider changes to the regulation market after receiving a cool reaction from stakeholders and the Market Monitor.

PJM officials drafted a proposed problem statement in response to the polar vortex in early January, when regulation market prices spiked to 4.5 times normal levels.

Regulation prices hit $3,296/MWh at the peak of the polar vortex as real-time energy prices rose above $1,800/MWh. Including lost opportunity costs — for example forgone revenue in the energy market — PJM rang up a $65 million bill for regulation in January.

PJM’s Jeff Schmidt said the jump was due in part to the fact that high-performing generators were being used for energy and reserves instead of regulation, leaving the RTO to rely on poorer-performing generators to maintain system frequency at 60 hertz. Regulation market prices can be influenced by poorer-performing resources because the calculation uses a “historic performance score” in the denominator.

The issue was first raised in PJM’s analysis of the system’s performance during January’s cold. PJM said stakeholders should consider whether the division by the performance score is appropriate and whether the minimum participation requirements are high enough. It also said they should consider whether to go short on regulation during system peaks.

But the 4x jump in regulation prices was actually far below the increases in operating reserve (10x) and synchronized reserve (9x) costs for the same period.

“I don’t understand why it’s a problem,” Market Monitor Joe Bowring said during a discussion before the Market Implementation Committee last week. “Poor-performing resources raised the prices. That’s exactly the way it’s supposed to work.”

Brock Ondayko of American Electric Power Energy Supply agreed with Bowring. “If we start weeding out the slower performers I guess you would end up with no regulation resources,” he said.

“That certainly could happen,” Schmidt acknowledged.

Public Service Enterprise Group’s John Citrolo said it was improper for PJM to take an “administrative role” in controlling volatility “rather than letting the market handle it.” He said load-serving entities can hedge against such risks.

John Webster of Icetec said increasing the performance requirement for regulation resources might actually increase prices.

After an extended discussion, MIC Chair Adrien Ford said she would table the matter, though PJM may bring it back at a later meeting.

Performance-Based Pricing

In response to the Federal Energy Regulatory Commission’s Order 755, PJM switched in October 2012 to performance-based regulation, which is intended to pay resources based on the accuracy, speed and precision of their response.

In the 2013 State of the Market report, the Monitor said that the changes had improved the regulation market, but that the market’s design remained “flawed,” including an incorrect definition of opportunity cost and an inconsistent implementation of the marginal benefit factor — a conversion calculation — in optimization, pricing and settlement.

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State Briefs

DELAWARE
Lawmaker Proposes Study for Power Aggregation

Colin Bonini
Colin Bonini

A Delaware lawmaker included a proposal for an electricity aggregation study into the state’s capital budget this year in a move that could lead to lower electricity prices for local governments and their residents. The measure, penned by state Sen. Colin Bonini (R-Dover South), calls for the assessment of local conditions and a study of best practices in other states. Aggregation programs allow for large groups to buy power in blocks, with the idea that the group could negotiate a better deal than the standard offer from utilities. Delmarva Power & Light officials said they were studying the proposal.

More: The News Journal

ILLINOIS

Wisconsin Energy Promises Rate Freeze in Acquisition

we-energiesSourceWEWisconsin Energy is promising to freeze rates and guarantee jobs for at least two years in an attempt to convince the Illinois Commerce Commission to OK its proposed acquisition of Integrys Energy Group. Wisconsin Energy is trying to buy Integrys, parent company of Peoples Gas and North Shore Gas of Illinois. The company said if it obtained ICC approval, it would freeze rates for Illinois customers and keep the same number of Illinois employees – about 2,000 – for at least two years, in addition to honoring all labor contracts. The ICC is only one of several state and federal approvals necessary for the acquisition.

More: Milwaukee Business Journal

NRG to Cut Emissions at 4 Coal Plants

NRG Energy said it has a plan to cut emissions at four of its coal-fired stations in the state that would bring the state more than halfway toward meeting new Environmental Protection Agency-mandated emissions limits. The company said it would stop burning coal at one of its Romeoville plant units, convert its Joliet plant to burn natural gas and upgrade the Pekin and Waukegan plants with new emissions-control technology. About 250 jobs would also be cut. NRG said the plan would cut about 16 million tons of carbon dioxide emissions a year. The plan would cost about $567 million, the company said.

More: Chicago Tribune (subscription required)

INDIANA

$400K Grant to Fund Small Solar Projects

The Indiana Association for Community Economic Development received a $400,000 grant to help start up small solar energy projects in the Indiana Michigan Power service territory. The grant, which came from a legal settlement between American Electric Power and the U.S. Environmental Protection Agency, will be used to start Solar Uniting Neighbors (SUN). The economic development association said the grant would be enough to provide funding for 10 to 17 solar installations.

More: WANE TV

MICHIGAN

Solar, Wind Metering Growing

Small-scale solar- and wind-power installations in the state have increased their energy production by 18% since 2012, according to a Public Service Commission report. Since a state-mandated metering system went into effect in 2008, the state has seen 1,527 customers enter the net metering program.Under a net metering program, when customers produce more electric energy than they consume, the excess is sent back to the grid and the customer gets a credit. The PSC report noted that the number of net metering customers increased from 1,330 in 2012 to 1,527 in 2013.

More: Michigan Public Service Commission

NEW JERSEY

Environmentalists Urge State to Rejoin RGGI

RGGISourceRGGIClean energy and environmental advocates urged state officials to rejoin the Regional Greenhouse Gas Initiative during a court-ordered hearing last week. Two years after Gov. Chris Christie withdrew from the RGGI, a state appeals court ruled that the administration and the state Department of Environmental Protection didn’t follow the proper rules, and ordered a hearing to reconsider the move.

While it is unclear whether the court-ordered hearing would have an effect on the decision, many speakers took the opportunity to urge state leaders to rejoin the regional effort.Doug O’Malley, the director of Environment New Jersey, which filed the lawsuit along with the Natural Resources Defense Council, said he hoped the legislature would invalidate the repeal. “Gov. Christie is on the wrong side of public opinion on his decision to pull New Jersey out of this landmark climate program,” O’Malley said.

More: New Jersey Herald

State Consumer Agency Calls for More Protection

The state Division of Rate Counsel is again asking the Board of Public Utilities to tighten rules governing third-party energy suppliers. The consumer advocate’s efforts were spurred by a tough winter, skyrocketing energy prices and widespread accusations of misleading or fraudulent business practices.

Rate Counsel Director Stefanie Brand said her new petition was produced after consultation with the Retail Energy Suppliers Association. “The most important improvement is increased disclosure, in clear and plain language, of all contract terms,’’ one part of the petition explains.

Some of the proposed rules mirror those being considered in the state legislature.

More: NJ Spotlight

Fishermen’s Energy Goes Forward with DOE Funds

fishermensenergySourceFishermensenergyWind energy developer Fishermen’s Energy signed an agreement with the Department of Energy last week, giving it access to almost $47 million to develop a 25-MW wind project off Atlantic City. The project seems to be going forward, even though the New Jersey Board of Public Utilities has denied it ratepayer subsidies and said the project is too expensive and risky. Fishermen’s is appealing that ruling.

One of the terms of the DOE grant is that the project have a customer for its energy one year from now. But the developers are optimistic. “Our goal here in Atlantic City is to build a commercially operational wind farm that demonstrates job creation and specifically to show that these types of projects create benefits that far exceed their costs,” said Chris Wissemann, Fishermen’s CEO.

More: Recharge

NORTH CAROLINA

Study: New State Policies Could Boost Solar

While North Carolina ranks fourth in the nation for overall solar capacity, it is only 10th per capita, behind cloudier states such as New Jersey and Massachusetts, according to a report by an environmental group calling for more solar-friendly state policies.

Environment North Carolina said the state has benefited from the rise of large-scale solar farms but lagged in residential and commercial rooftop systems. The report recommends the state enable third-party sales of electricity, improve net metering laws and expand renewable energy standards.

More: Environment North Carolina

OHIO

State to see 1,000th Utica Shale Well

The state Department of Natural Resources said the 1,000th Utica Shale well will be drilled as early as this week. Through last week 997 horizontal wells had been drilled out of 1,428 permits issued since the shale boom started in 2010.

More: Columbus Business First

Net Metering Case Headed to High Court

OhioSupremeCourtSourceOHIOThe Ohio Supreme Court will be called on to determine how much net metering customers should be paid for electricity they feed back into the grid in a case pitting the Public Utility Commission of Ohio against several large utilities.

PUCO ruled recently that net metering customers are entitled to full value of the electricity, including capacity. FirstEnergy and American Electric Power have argued that their compensation should be based only on the energy portion of their bills. AEP appealed PUCO’s latest ruling, in July, to the state Supreme Court.

More: Midwest Energy News

PENNSYLVANIA

PUC Ponders Limits on Solar Net Metering

The Public Utility Commission is considering a rule that would limit the amount of solar energy customers can sell back to the grid. “By customer-generators producing more electricity and selling it back to the grid and the utility, this could actually be passed through and affect the rates for other customers,” PUC spokeswoman Robin Tilley said. The proposed rule would limit energy production for households and businesses to 110% of annual consumption. The solar industry opposes the rule.

More: WHYY

WEST VIRGINIA

Chesapeake Energy Eyes Shale Fields

CHK_3C_logo.epsState Department of Environmental Protection filings show that Chesapeake Energy, one of the largest shale gas energy players in the Midwest, is looking at the state as its next gas frontier. Chesapeake was one of the first companies to start drilling into Ohio’s Utica Shale Field. The Point Pleasant formation, in West Virginia, could be the scene of the next rush for shale gas production. State Department of Environmental Protection files show that Chesapeake is outlining plans to drill wells in the Point Pleasant formation.

More: Columbus Business Journal

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Norris Departure Opens Another FERC Seat

ferc
(Source: FERC)

It’s time for President Obama to start reviewing resumes again.

Just days after Norman Bay was sworn in as the Federal Energy Regulatory Commission’s fifth member, Democrat John Norris announced he will resign his position almost three years early, creating yet another opening on the panel.

Bay was sworn in Monday after taking a swipe at the PJM energy traders who had dogged him through his confirmation process.

On Friday, Norris confirmed long-standing rumors of his departure by announcing he will leave FERC Aug. 20 to take a post as the Minister-Counselor for the U.S. Department of Agriculture in Rome.

In between, newly promoted Chairman Cheryl LaFleur asserted her authority by filling the General Counsel’s post.

All in all, just another week at 888 First St. NE.

In one of his last acts as director of the FERC Office of Enforcement, Bay authorized the issuance of a Staff Notice of Alleged Violations against a group of investors over what staff said was illegal “wash” trades intended to capitalize on transmission line-loss rebates in PJM.

The notice, issued Tuesday, targets Kevin and Richard Gates, who launched a publicity campaign and lobbied against Bay’s nomination to highlight their complaints over FERC’s investigation. (See related story, PJM UTC Case Likely Headed to Court.)

Obama had indicated his intent to make Bay chairman immediately after his confirmation. But in order to win crucial votes in the Senate, the White House agreed to delay Bay’s promotion until April 15.

Cheryl LaFleur Flexes

That makes LaFleur, who had served as acting chair since November, kind of a Cinderella chairman.

But, apparently emboldened by Obama’s decision July 30 to remove her “acting” title, she asserted her authority Thursday by doing the same for former acting General Counsel David Morenoff, who has been doing that job since October 2012.

Meanwhile, Norris announced he would leave — not to return to his home in Iowa, as some had expected, but to Italy, thanks to Secretary of Agriculture Tom Vilsack.

Norris had served as Vilsack’s chief of staff, both in the Agriculture Department and before, when Vilsack was Iowa’s governor.

Norris issued a statement praising his FERC colleagues before heading off to a camping trip in Maine with his family. He was unavailable for comment yesterday.

Colette Honorable Next?

ferc
Colette Honorable

With Norris departing, speculation on his replacement has focused on Arkansas Public Service Commission Chair Colette Honorable. She was named chair of the Arkansas commission by Gov. Mike Beebe, whom she previously served as chief of staff when he was attorney general. Her six-year term expires in 2017. Honorable is also three-quarters through her one-year term as president of the National Association of Regulatory Utility Commissioners (NARUC).

A lawyer and native of Little Rock, she previously served as executive director of the Arkansas Workforce Investment Board and as an attorney in the Attorney General’s Office, where she worked on Medicaid fraud cases. She has also worked as an attorney at the Center for Arkansas Legal Services, a law clerk in the Arkansas Court of Appeals and as an assistant public defender.

She did not return a request for comment yesterday.

Lame Duck

Norris’ departure was widely expected after he told a conference in June that he would not seek renomination when his term ended in 2017. Norris said industry stakeholders had told him he could not win Senate confirmation if he was reappointed because he is too “pro-consumer.”

Last year, Norris blasted Senate Majority Leader Harry Reid (D-Nev.) for blocking his bid to become FERC chair. Norris said Reid had opposed his elevation to chairman because the majority leader thought he was “too pro-coal” during his time on the Iowa Utilities Board.

Since last year, Norris has increasingly forged his own path. After issuing 11 dissents or concurring statements in 2010, and 11 in 2011, he issued 19 last year and 11 through the first six months of 2014.

Norris’ wife Jackie ran the 2008 Obama campaign in Iowa and briefly served as Michelle Obama’s chief of staff; she is now executive director of the Points of Light Corporate Institute, an organization that helps companies develop employee-volunteer programs, in D.C.

Before Norris’ announcement last week, an editorial in The Storm Lake Times urged him to return home to run for office, suggesting he was one of the few Democrats who could oust Rep. Steve King or Gov. Terry Branstad. He had run unsuccessfully for the House in 2002.

The Work Goes On

Republican Commissioner Tony Clark said yesterday he will miss working with Norris, who he has known since they were both state regulators.

Clark said while it would be nice to have a full panel, there haven’t been many occasions when the panel locked in 2-2 ties.

While Bay may emphasize new initiatives when he becomes chair, Clark said, much of the commission’s day-to day activities will be unchanged. “A lot of the work is just driven by the filings themselves,” he said.

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PJM: Can’t Delay Interface Postings for FTR Auctions

interfacePJM officials last week defended their practice of creating interfaces to capture operator actions in response to voltage problems, saying they can’t guarantee the constraints will be modeled in Financial Transmission Right auctions.

In the last year, PJM has created “closed loop” interfaces in at least four locations so that operator actions — such as sub-zonal dispatch of demand response — are captured in Locational Marginal Prices rather than uplift. PJM said it must use the interfaces to set prices because its modeling software can only set prices for thermal constraints, not voltage problems.

But in its effort to reduce uplift, PJM is exacerbating FTR underfunding, DC Energy’s Bruce Bleiweis told the Market Implementation Committee during a discussion last week.

PJM has promised to provide notice of any new interfaces at least one day before implementing them. But that’s not enough time for FTR holders to react, said Bleiweis, who noted that the RTO requires 90 days’ notice before implementing special protective schemes (SPS).

He proposed PJM provide notice of the potential need for a new constraint as soon as it has identified one and discuss the results of their analysis at the next meeting of the MIC or Markets and Reliability Committee. Interfaces should be announced prior to the next FTR or Balance of Planning Period auction and not implemented until the beginning of the next month, Bleiweis said.

PJM “shouldn’t be in the position of choosing who will gain and who will lose,” he said.

PJM officials said Bleiweis’ proposal was unworkable.

“A lot of those things come up quicker than the time that Bruce would want,” said Adam Keech, director of wholesale market operations. “We might know two days before we need it, not 45 days. Forty-five days later we may not need it. We’re just printing uplift in between.”

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Company Briefs

VivintSourceVivintVivint Solar, an upstart business in the home security and automation fields, is planning an initial public offering for its solar segment, according to sources. Vivint’s IPO could come out as soon as September.

Vivint is the second biggest residential solar installation company in the U.S., behind SolarCity, which went public in December 2012 at $8 per share. Solar City shares closed Friday at $70.14.

More: Utility Dive

Sunoco Logistics Eying 2nd Shale Gas Pipeline

Sunoco Logistics, still finalizing its first cross-state pipeline in Pennsylvania to transport Marcellus Shale gas liquids, has already signed up a customer for a second pipeline. Austrian chemical company Borealis signed a 10-year agreement to buy ethane produced in the Marcellus and Utica shale fields. Ethane is used in plastics production.

The new agreement would go into effect in 2016. Sunoco is in the final stages of constructing its first line, Mariner East. It is scheduled to go into operation later this year. That project generated controversy among residents of the areas the pipeline crossed. Sunoco has been asking the state Public Utility Commission to designate the pipeline a public utility, which would ease the process of gaining rights of way. So far, it has been unsuccessful.

More: The Philadelphia Inquirer

LaSalle Unit 2 Shuts Down with Valve Problem

(Source: Exelon)
(Source: Exelon)

Unit 2 at Exelon’s LaSalle Nuclear Generating Station went into automatic shutdown last Tuesday when one of the station’s steam valves closed. The shutdown went according to plan, and no damage or impact on customers occurred, a station spokesperson said. The company is looking into the cause.

More: News Tribune (subscription required)

TVA Layoffs Reduced by Attrition, Retirements

The Tennessee Valley Authority said last week that it will accomplish most of its 2,000 job reductions through attrition, retirements and voluntary resignations, avoiding the need for massive firings. The cuts are TVA’s largest in 20 years.

TVA began the year with about 12,500 employees. This is down from 51,000 employees in 1981. TVA President Bill Johnson said the employee reductions are necessary in order to cut down on expenses and to keep electricity rates competitive in the region.

Labor unions are concerned that the layoffs merely mean that TVA is hiring more contractors. “As TVA is laying off some of our workers, they are filling some of that work with contractors or selecting managers or others to do the work from outside of our bargaining unit. Those are our major concerns,” said Faye Headrick, senior international representative for the Office and Professional Employees International union. The union represented 3,000 TVA employees 40 years ago but only about 600 now.

More: Chattanooga Times Free Press

FirstEnergy’s Harrison Plant Union Gets Contract

Workers at FirstEnergy’s Harrison Power Station in Haywood, W.Va., have been given their first contract. The Utility Workers Union of America, which has been negotiating since 2010, announced the contract last week. The coal-fired plant employs 184 workers. They’ve been fighting for a contract since they voted to unionize in September 2010. The 3.5-year collective bargaining agreement covers wages, benefits and working conditions. The plant was owned by Allegheny Energy and became part of FE’s fleet through a merger in February 2011.

More: The State Journal

PSEG One Step Closer to Permit for New Nuke

PSEG Nuclear is close to filing a draft environmental impact study on its plan to build a new nuclear station on Artificial Island. The company would need to complete a land swap of 631 acres with the U.S. Army Corps of Engineers on the island in order to go forward. Other studies, including a storm surge study, are also necessary. The environmental impact study could be filed as soon as September. Final action could come late next year, with a separate decision on technologies, design and construction to follow.

More: The News Journal