Search
December 23, 2024

Posted on

MC/MRC Final Approval: Demand Response Changes

Demand response providers will face increased scrutiny and be required to provide additional documentation under changes given final approval by the Markets and Reliability Committee March 28.

The new rules require Curtailment Service Providers bidding into the capacity auction to have a company officer sign a certification attesting to the company’s intent to physically deliver MWs. Bids will be made through an offer template to increase the consistency of information supplied. PJM also will increase its scrutiny of delivery zones in which CSPs’ bids exceed DR penetration thresholds.

The changes involved modifications to the OATT, Operating Agreement and Manual 11. Click here for details.

Baseline measurements, information requirements, duplicate registrations

The Members Committee gave final approval March 28 to changes that:

  • Clarify the use of emergency and economic baseline measurements and settlements;
  • Expand and clarify information requirements for Curtailment Service Providers, and
  • Establish procedures for resolving duplicate registrations.

The changes required modifications to Manual 11. Click here for details.

Posted on

PJM’s `To Do’ List

(Washington, DC) The Federal Energy Regulatory Commission’s 195-page order released late Friday afternoon requires PJM or its transmission owners to make additional filings to achieve full compliance with Order 1000. Those tasks, which largely involve changes to the Open Access Transmission Tariff (OATT) and Operating Agreement (OA), are listed below, along with references to the relevant paragraphs in the order (docket #s ER13-198, ER13-195 and ER13-90).

The order is broken into three categories (click to jump to that section):

Transmission Planning

Schedule for implementing Order 1000 changes 

To Do:
  • Establish a start date for the next 12-month and 24-month planning cycle during which PJM’s proposed revisions will be effective or provide an alternative effective date and explain why it is appropriate.
  • Provide further information regarding PJM’s transition to the revised transmission planning process and explain how PJM will evaluate transmission projects currently under consideration. (P 34)
Background:

FERC said PJM Manual 14B was unclear regarding whether the planning cycle starts in January or the prior December.  The commission said it expects PJM to implement the Order 1000 changes at the beginning of the next planning cycle, saying “we do not believe that it is necessary to delay the effective date of the proposed revisions until every issue in this proceeding has been resolved.” (P 32)

Comparability

To Do:

Explain how PJM will continue to comply with the requirement that it evaluate transmission, generation, and demand resource alternatives on a comparable basis when seeking solutions to transmission constraints and reliability problems. (P 53)

Background:

Order 1000 builds on the transmission planning principles of Order 890, which requires that transmission planners consider generation and demand response proposals as well as new transmission lines when developing assumptions used in the planning process.

PJM has proposed removing language in Schedule 6 of its Operating Agreement which relate to procedures for stakeholders seeking to propose alternative transmission solutions. The commission said it relied on these sections when it found PJM in compliance with Order 890’s comparability principle in 2009. (P 46)

The commission also took issue with PJM’s position that participants in the regional transmission planning process must be a member or associate member of PJM. “This appears to be a misstatement by PJM,” the commission wrote, noting that such a requirement would conflict with Order No. 890 and the PJM Operating Agreement. (P 55)

The commission rejected a request by a coalition of environmental groups that said that PJM’s planning procedures fail to ensure comparable treatment of demand response. The groups asked FERC to require PJM to collaborate with the Independent State Agencies Committee and other stakeholders to develop more specific procedures and metrics on how PJM will evaluate all options on a comparable basis and select more efficient or cost-effective solutions.

The commission said the issue of cost recovery for non-transmission alternatives is beyond the scope of Order No. 1000. The commission also rejected the organizations’ request that it require PJM to provide technical assistance or funding to such groups. (P 53-54)

Identifying More Efficient or Cost-Effective Transmission Solutions

To Do:

None

Background:

The commission rejected as outside the scope of Order 1000 Clean Line Energy Partner’s request that PJM include participant-funded merchant projects in the Regional Transmission Expansion Plan (RTEP). (P 66)  Clean Line said allowing study of merchant projects in the RTEP “rather than waiting several years for an interconnection agreement,” would support the commission’s goal of identifying the most cost-effective solutions to transmission needs. (P 63)

Incorporating Public Policy Requirements

To Do:
  • Revise the tariff to describe the process through which PJM will determine which public policy requirements identified by stakeholders at the assumptions stage of the RTEP will be incorporated into transmission studies. (P 115)
  • Explain how the transmission-owning members of PJM are addressing public policy requirements in their local transmission planning processes. (P 123)
  • Revise the tariff and OA to include laws or regulations passed by local governments (e.g., municipalities and counties) in the definition of public policy requirements. (P 113)
  • Post on the PJM website an explanation of those public policy requirements that PJM adopted at the assumptions stage of the RTEP and why other public policy requirements introduced by stakeholders were excluded. (P 116)
Background:

The commission said it was unclear whether PJM intends to incorporate all public policy requirements identified by stakeholders into its transmission studies, or whether it will consider only a subset of requirements. The commission also said it was unclear what information PJM intended to post on its website regarding inclusion of public policy needs or how PJM transmission owners have incorporated Order 1000 requirements in their local transmission planning processes.

State Agreement Approach

To Do:

Identify the entity that determines whether a “Supplemental Project” will be included in the RTEP. (P 145)

Background:

Under PJM’s “State Agreement Approach,” states can submit to PJM for inclusion in the RTEP projects that address public policy requirements even if the project doesn’t qualify as a reliability or market efficiency project. The project will be included in the RTEP as a state public policy project or a “Supplemental Project” if the states voluntarily agree to pay for them. Costs for such projects cannot be allocated to any state that does not agree to those costs.

PJM’s filing specifies that Supplemental Projects are not subject to PJM board approval but doesn’t identify which entity determines whether such projects will be included in the RTEP. A Supplemental Project is one that the Office of the Interconnection deems not required for compliance with PJM’s system reliability, operational performance or economic criteria.

Top

Nonincumbent
Transmission Developer Reforms

Federal Rights of First Refusal

To Do:

Revise or eliminate any provisions in the OATT and agreements “that could be read as supplying a federal right of first refusal” (ROFR) for any transmission projects selected for regional cost allocation. (P 221)

Background:

The commission sought to clarify its ruling in the Primary Power Rehearing Order, in which it found that PJM’s rules allow a nonincumbent transmission owner to receive cost-based or cost-of-service compensation for an economic transmission project. The commission said it now believes that PJM’s OATT and agreements “are ambiguous and open to interpretation and potential undue discrimination.” The commission said PJM’s revisions must also comply with its Atlantic City ruling by addressing any provisions “that could purport to preclude the section 205 filing rights of nonincumbent utilities without their consent.”

—-

To Do:

Remove proposed language reserving to incumbents:

  • Transmission projects that are proposed on a transmission owner’s right of way when that project would alter the owner’s “use and control of its existing rights of way under state law” or
  • Projects “when required by state law, regulation or administrative agency order.” (P 231)
Background:

The commission said the two exceptions improperly establish federal rights of first refusal.

The commission acknowledged that Order 1000 did not require PJM to remove from its tariffs and agreements references to state or local laws regarding the construction and siting of transmission facilities. “However, PJM’s proposal goes beyond mere reference to state or local laws or regulations; it references state and local laws and then uses that reference to create a federal right of first refusal,” the commission said.

Similarly, Order 1000 did not alter incumbents’ use and control of its existing rights-of-way. “However, the Commission did not find that … a public utility transmission provider may add a federal right of first refusal for a new transmission facility built on an existing right-of-way.”

Transmission Upgrades

To Do:

Clarify PJM’s definition of a transmission “upgrade.” (P 234)

Background:

Order 1000 reserved construction of transmission reliability upgrades — which it defined as including tower change outs and reconductoring — to incumbent utilities. The commission said PJM’s OATT and agreements contain references to several types of upgrades and it is unclear which PJM intends to include in the Order 1000 definition.

Short-term and Long-lead Projects

To Do:

Revise the OA and OATT to:

  • List and explain the criteria that PJM will use to determine whether to change the default proposal window for Short-term and Long-lead projects. (P 239)
  • Clarify into what category in the transmission project proposal process a market efficiency project can be proposed. (P 237)
  • Explain how PJM will determine whether there is insufficient time for re-posting and reevaluation, and how such a determination requires that an incumbent transmission owner be assigned to build a Long-lead project. (P 241)
Background:

FERC approved PJM’s proposal to establish three categories of transmission projects for evaluation: Immediate-need reliability projects, Short-term projects and Long-lead projects.

Immediate-need projects and certain short-term projects would be assigned to incumbents. The commission said these “time-based” exceptions to the elimination of the federal ROFR are permissible for urgent reliability projects in which there is insufficient time to conduct open solicitations. (PJM proposed  a 30-day proposal window for Short-term projects; if the first set of proposals does not address all of the reliability violations required to be solved, PJM will designate that work to the incumbent.)

The commission said PJM’s proposals made it unclear whether economic projects would be classified like reliability projects as Short-term or Long-lead.

Immediate-need Reliability Projects

To Do:

Explain how its designation of Immediate-need reliability projects complies with five criteria created by the commission. (P 248)

Background:

The commission said the criteria were needed to ensure that the ROFR exceptions “will be used in limited circumstances.” The criteria are:

  1. The Immediate-need Reliability project must be operational in three years or less to solve reliability criteria violations.
  2. PJM must post a public explanation of the reliability need and why it is time-sensitive.
  3. The process used to assign an Immediate-need project to an incumbent must be outlined in PJM’s OATT. PJM also must provide stakeholders a written explanation of the decision to assign the project to an incumbent, including a description of other transmission or non-transmission options that the RTO considered and an explanation of why the reliability need was not identified earlier.
  4. Stakeholders must be permitted time to provide comments in response to the description in criterion three and such comments must be made publicly available.
  5. PJM must maintain and post a list of prior year designations of all projects for which the incumbent transmission owner was designated as the entity responsible for construction and ownership.

The commission also told PJM to explain why it proposed allowing the Office of the Interconnection authority to designate projects with an in-service date of longer than three years as Immediate-need projects and how PJM will exercise that discretion. (P 252)

Qualification Criteria

 To Do:

Clarify that the selection criteria for those seeking to be awarded transmission projects, and the requirements for those awarded such projects (e.g., posting letters of credit) apply to both incumbent transmission owners and nonincumbent transmission developers. (P 276)

Background:

The commission said some of PJM’s language on the selection process and developer requirements was vague.

The commission rejected as beyond the scope of this proceeding suggestions by the PJM Market Monitor that PJM implement a competitive process for the procurement of capital. The commission also declined to require PJM to include additional criteria proposed by Duquesne Light Co., Exelon Corp. and the New Jersey Board of Public Utilities. The commission said the additional criteria were not necessary to comply with Order 1000 but said the parties could seek to add them through the stakeholder process.

Transmission Proposal Evaluation Process

To Do:
  • Provide additional clarification regarding the evaluation of more efficient or cost-effective solutions. (P 310)
  • Propose a process through which PJM will publicly provide generally applicable information arising from the RTO’s private discussions with incumbent and nonincumbent  bidders. (P 311)
Background:

LS Power raised concerns that PJM has not provided enough detail about how it will determine which proposals provide the most efficient or cost-effective solutions.

LS Power also protested that confidential discussions between PJM and the incumbent transmission owner during the proposal window may lead to discrimination against nonincumbents. FERC declined to adopt LS Power’s proposal that only public discussions be permitted between PJM and stakeholders during the proposal window and evaluation process.

The commission also rejected the market monitor’s contention that a cost cap on transmission projects be required to prevent bidders from submitting unrealistically low bids to win the project and then seek more money later through change orders.  FERC said such abuses should be policed by PJM’s requirement that bidders provide letters of credit in an amount of the difference between their bid and the next lowest bid.

Reevaluation Process

To Do:

Explain how PJM will determine whether to retain or remove a selected transmission project, or select an alternative transmission solution, under the reevaluation process. (P 318)

Background:

PJM will reevaluate projects in which the developer fails to meet its obligations (e.g., failure to provide a development schedule or letter of credit, or failure to meet a milestone that delays a project’s in-service date). Based on that reevaluation, PJM will decide whether or not to reopen the project to other developers or seek an alternative solution.

The commission said the lack of description regarding how PJM will decide a project’s fate “may allow PJM too much discretion in making this determination.”

Cost Recovery

To Do:

Explain how the various provisions of the OATT and agreements ensure that a nonincumbent selected to construct a transmission project can recover costs. (P 327)

Background: 

FERC found that parts of the OATT and other agreements appear to conflict with each other and contain provisions “that appear to preclude nonincumbent transmission developers from filing for transmission cost-based rates prior to becoming a party” to transmission owners agreement.

Top

Cost Allocation

Impacts on Neighboring Regions

To Do:

Revise the OATT to describe how PJM will identify the impact of a new transmission facility on neighboring regions and how costs will be allocated if PJM agrees to bear them for with any upgrades required in the other regions. (P 422)

Background: 

FERC’s rules require PJM transmission planners to identify whether projects within PJM will require upgrades in neighboring regions. Because PJM cannot assess costs for such upgrades on other regions without their agreement, FERC said it must develop a way to allocate such costs within the RTO.

Direct Current Transmission Lines

To Do:

Establish criteria that consider DC and AC transmission in a comparable manner for qualification for regional cost allocation. (P 439)

Background: 

The commission said that the Transmission Owners’ October 11 filing “may discriminate against DC transmission facilities” in its proposed definition of facilities qualifying for regional cost allocation. The filing would disqualify a DC facility that is not connected to at least one substation or switching station also connected to a minimum 500 kV or double-circuit 345 kV transmission line. The transmission owners put no such conditions on AC facilities.

Solution-based distribution factor analysis (DFAX)

To Do:

Provide more details explaining how the Solution-Based DFAX method is used to calculate assignments of cost responsibility. (P 428)

Background:

The commission agreed with Long Island Power Authority, Illinois Commerce Commission, and the Maryland Public Service Commission that PJM had not provided enough detail regarding how DFAX will be implemented. “While PJM has adequately shown how the DFAX values and usage of transmission facilities will be calculated, there is no detail regarding how these values will be utilized to calculate assignments of cost responsibility,” the commission said.

Top

Posted on

PJM TOs’ ROFR Bid Rejected — UPDATE 2

By Rich Heidorn Jr.
PJM Insider

WASHINGTON, D.C. (March 21, 2013) — The Federal Energy Regulatory Commission today rejected a bid by PJM transmission owners to retain their rights of first refusal over transmission reliability projects while approving the owners’ proposed “hybrid” cost allocation for new high-voltage lines.

In Order 1000, the commission reversed previous FERC policy that allowed “incumbent” utilities rights of first refusal (ROFR) to add new lines. The commission said it would review transmission owners’ objections to the removal of ROFR individually.

In their Oct. 25 compliance filing (ER13-195-000) the PJM transmission owners said their ROFR privileges are embedded in the Transmission Owners Agreement and Operating Agreement. They said those rights are protected by the Supreme Court’s Mobile-Sierra standard, which presumes the validity of terms in freely negotiated wholesale energy contracts unless the contract “seriously harms the public interest.”

But the commission said the Mobile-Sierra protections apply only to contracts between parties of differing interests, in which there is a presumption that the negotiated terms are just and reasonable. The PJM agreements carry no such presumption because of the like interests of the transmission owners that formed the organization.

“We didn’t think it could be applied to this type of agreement. It’s not like a contract at arm’s length,” Chairman Jon Wellinghoff said in a news conference after the meeting. “What you have are multiple parties that formed an organization.”

The commission’s 3-2 decision, which came in response to compliance filings required by FERC’s landmark Order 1000, won’t be the last word on the issues. The right of first refusal is among the issues cited in more than a dozen challenges to Order 1000 that have been filed in the U.S. Court of Appeals for the District of Columbia.

“Hybrid” Cost Allocation Approved
ER13-195
PJM Order 1000 Cost Allocation

The commission was more sympathetic to transmission owners’ proposed revisions to PJM’s transmission cost allocation rules. The new rules expand the definition of Regional Facilities to include double 345kV lines in addition to those 500kV and higher.

Costs for such lines will be allocated on a hybrid approach: one-half allocated on a postage-stamp basis (to zones on a load ratio share basis and to merchant transmission facilities in proportion to awarded Firm Transmission Withdrawal Rights) and the other half allocated to specifically identified beneficiaries of each project.

For reliability projects, beneficiaries will be identified based on the results of a revised distribution factor (“DFAX”) analysis.

For economic projects, beneficiaries will be identified based on each zone’s and each merchant transmission facility’s share of the zonal decreases in load energy payments that result from the new facility. This is the same methodology PJM currently uses for lower voltage economic projects.

The new allocation rules will also apply to lines below the voltage threshold that must be constructed or strengthened to support new Regional Facilities, so-called “Necessary Lower Voltage Facilities.”

The costs for lower voltage facilities not necessary for Regional Facilities will be allocated 100% to beneficiaries based on the same rules.

The proposal replaces the current violations-based DFAX analysis to a “solution-based” evaluation. The violation-based DFAX evaluates the contribution of load and merchant transmission facilities to flows on the facility that requires improvements to avoid reliability violations.

In contrast, the new solutions-based approach determines the relative use that load in each zone and withdrawals by merchant transmission facilities are projected to make of the new facility. Uses of the new facility in both directions are taken into account.

Munis Welcome ROFR Removal

Order 1000 required transmission providers to remove from their FERC tariffs and agreements any provisions that grant a federal right of first refusal to transmission facilities that are selected in a regional transmission plan for cost allocation. The order doesn’t affect the right of an incumbent transmission provider to build and recover costs for upgrades to its own transmission facilities. Also unaffected were incumbent transmission providers’ use and control of their existing rights of way

Municipal utilities welcomed the elimination of the preference as a way for them to share in ownership of new facilities and thus reduce the cost impact on their ratepayers. Load-serving utilities without transmission say incumbents have used the preference to block or delay new transmission needed for them to access competitors’ generation.

Independent transmission developers say they are reluctant to invest time and money developing transmission projects because incumbents can take control of the project after its benefits have been demonstrated.

High Standard of Proof

The commission’s determination that PJM’s ownership and operating agreements were not arm’s-length contracts allowed regulators to sidestep the high hurdle the Supreme Court for rejecting Mobile-Sierra contracts. The court said that rates set by a freely negotiated wholesale energy contract are presumed to be just and reasonable unless FERC concludes that the contract “seriously harms the public interest.” The D.C. Circuit has called the public interest standard “practically insurmountable.”

The transmission owners had hoped to force FERC to meet the standard. The owners noted that PJM transmission owners have built $5 billion in transmission expansions and upgrades since PJM became an RTO. “The Commission has not disallowed any of these costs. In other words, the ROFR has produced no costs in excess of what is just and reasonable.”

Transmission owners in New England, the Midwest ISO and the Southwest Power Pool also cited the Mobile-Sierra standard in seeking to retain their ROFRs. Transmission owners in MISO said that eliminating their rights to construct new transmission within their own systems could result in “substantial erosion” of company revenue.

Split Vote

Commissioners Philip D. Moeller and Tony Clark dissented on the PJM and MISO votes, saying they believed the orders will impede efforts to accelerate transmission construction.

Moeller said the commission’s PJM order was likely to discourage transmission construction. “As I observed in my partial dissent on Order No. 1000, `instead of encouraging more regional cooperation, the rule could ultimately discourage such cooperation by encouraging more local transmission projects,’” he wrote.

Clark wrote that he disagreed with the majority’s finding that allowing PJM “to acknowledge the reality of certain state and local laws in its planning process was a violation of these Order No. 1000.” As a result, he said, “PJM will be compelled to approve projects that may have no legal possibility of ever being built.”

“The Commission’s decision puts PJM on a collision course for litigation, as opposed to a pathway towards transmission development,” he added.

The commission found that PJM, MISO and WestConnect “partially comply” with Order 1000 but will need to make additional filings to clarify and refine their plans.

PJM was ordered to provide more detail on the solution-based DFAX and how planners will evaluate the impact of the RTO’s upgrades on neighboring regions. The commission also asked for more information on how PJM will determine whether new direct current transmission lines qualify for regional cost allocation.

MISO was ordered to provide more detail on how it will qualify and select transmission developers to build future projects. Wellinghoff said MISO gave costs only a 30% weighting in the selection criteria. “Other selection criteria seemed more like qualification criteria.”

WestConnect has the most work to do in its next compliance filing. The commission rejected WestConnect’s cost allocation plan, saying it cannot be voluntary.

Posted on

Monitor Calls for Fixes to Capacity, Reserve, Demand Response

By Rich Heidorn Jr.

Washington, DC (March 14, 2013) – Market Monitor Joseph Bowring released the 2012 State of the Markets report with a call for changes to the capacity market, demand response and operating reserves.

2012 State of the Markets at a Glance
2012 State of the Markets at a Glance

The report showed that average LMP prices fell 23% to $48.55, the lowest levels in more than a decade, as energy demand remained modest and cheap coal was displaced by even cheaper natural gas. Capacity prices fell 37% while congestion costs dropped by nearly half. Peak load dropped 2.3% from 2011 (a 5.7% drop if load from the Duke Energy Ohio/Kentucky transmission zone, which joined PJM in the first quarter of 2012, is excluded).

“It was a very favorable year for prices but there’s no reason to expect that dynamic to continue,” Bowring said at a news conference at which he summarized the 499-page report.

While energy and capacity prices were down, transmission service charges increased 17% and day-ahead operating reserve charges jumped 90%.

Recommendations Repeated

For those who have read previous editions, this one will no doubt be familiar. Bowring estimated two-thirds of his 58 recommendations were repeated from last year’s report.  The capacity market, operating reserves and demand response accounted for more than two-thirds of the monitor’s proposed reforms.

As in 2011, the monitor continued to find all but one of PJM’s markets competitive in performance if not in structure.

2012 State of the Market: Competitiveness Findings
2012 State of the Market: Competitiveness Findings

The regulation market, which failed in 2011 also was judged not competitive in 2012, although it received an “indeterminate” grade for the fourth quarter.  The market structure was judged not competitive for the year because at least one pivotal supplier failed the three pivotal supplier (TPS) test in 43% of the hours in 2012. The market performance was judged not competitive in the first three quarters,  despite competitive participant behavior, because the calculation of the opportunity costs resulted in prices greater than the competitive price in some hours and less than the competitive price in others.

The monitor said it was too soon to determine the impact of a new market design introduced in the fourth quarter. Parts of the design remain to be decided by FERC.

Generation Shifts

Coal-fired generation dropped 7.4%, with coal’s market share falling to 42%.  Natural gas made up the slack, with a nearly 40% jump in generation pushing it to nearly 19% market share. Combined cycle plants are increasingly called on as baseload resources, Bowring said.

2012 State of the Markets: Generation by Fuel Source
2012 State of the Markets: Generation by Fuel Source

Wind generation increased by nearly 15% and solar power output quadrupled but they remained small contributors (1.6% and less than 1%, respectively). Nuclear power’s share remained virtually unchanged with a 35% share.

The shift from coal to gas contributed to a 47% drop in congestion costs, to $529 million versus nearly $1 billion in 2011. Congestion costs also were reduced by revenues from Auction Revenue Rights and Financial Transmission Rights, which offset more than 80% percent of congestion costs for the year.

The monitor’s analysis identified 3,725 MW of generation at risk of retirement because of their inability to cover avoidable costs from total market revenues. This is in addition to 21,000 MW already forecast to retire. Still, coal’s market share “won’t go dramatically lower than” 40%, Bowring said.

Operating Reserves

Operating reserve charges in the day-ahead market spiked dramatically in September, resulting in an 87% increase in total charges for the year. The increase resulted after PJM increased the number of “must run” units in the Day-Ahead Energy Market because the units were regularly needed for reliability in real time.

2012 State of the Market - Operating Reserve Charges 2011 vs. 2012 (Source: Monitoring Analytics)
2012 State of the Market – Operating Reserve Charges 2011 vs. 2012 (Source: Monitoring Analytics)

Bowring made a dozen recommendations to address the issue, noting that the charges are not subject to competition, and cannot be hedged against. The charges were paid to a small number of units, with the top 10 units, representing less than 1% of PJM’s generator fleet, receiving 23% of credits and the top 10 organizations collecting almost 82% of the total.

The monitor said PJM needs to be more precise in defining why it pays operating reserves. “The goal should be to have dispatcher decisions reflected in transparent market outcomes to the maximum extent possible and to minimize the level and rate of operating reserve charges,” the report said.

The monitor also called for a review of the allocation of operating reserve charges to ensure that such charges are paid by all responsible for incurring the charges, including those participants using up-to congestion (UTC) transactions. PJM’s deviation rate for the year would have been reduced by 59% if up-to congestion transactions had been included in the calculation of operating reserve charges, the report said.

Summary of Recommendations

Capacity market
  • Eliminate 2.5% demand reduction.
  • Eliminate limited and summer unlimited products.
  • Improve performance incentives.
  • Eliminate OMC outages.
  • Require same modeling assumptions for all MOPR projects.
Energy market
  • Eliminate FMU/AU adders.
Market Monitors Recommentations by Category
Market Monitors Recommentations by Category
Operating reserves
  • Improve process of identifying reasons for paying credits and allocating charges.
  • Use operating schedule to calculate energy LOC.
  • Treat start up and no load costs as costs.
  • Require up to congestion transactions to pay operating reserve charges, after analysis.
 Demand response
  • DR should be classified as economic and not emergency program.
  • Improve measurement and verification and compliance reporting.
Planning
  • Remove projects from the queue if not viable.
Ancillary
  • Implement consistent treatment of marginal benefits factor in the Regulation Market.
  • Use operating schedule to calculate LOC.
Transactions
  • Require UTC to pay a fee during evaluation of operating reserves issues.
  • Implement rules to prevent sham scheduling.
FTRs
  • Correct the reporting of payout ratio.
  • Eliminate portfolio netting.
  • Ensure symmetric treatment of counter flow FTRs for payout.
Posted on

Natural Gas Group Seeks Voice in West Virginia Coal Plant Acquisition

West Virginia’s natural gas industry wants to intervene in the Public Service Commission’s review of FirstEnergy’s Monongahela Power Co.’s request to purchase a majority share of the Harrison power plant from another FirstEnergy affiliate.

The West Virginia Oil and Natural Gas Association, which represents gas producers, shippers, and distributors, said in a March 11 filing that it “desires the opportunity to express its views to the Commission about using natural gas as inexpensive, clean and reliable fuel for power generation.”

Richard L. Gottlieb, attorney for the group, said that while the state has historically relied on coal for electric generation, the commission should reconsider that reliance due to the increased availability, low cost and reduced carbon emissions of natural gas.

New Reality

“That’s simply reflecting the new energy reality in West Virginia,” Gottlieb told PJM Insider in an interview yesterday. “That’s something we should acquaint the PSC about if they’re not already.”

Monongahela Power’s (Mon Power) proposed acquisition is already facing opposition from the West Virginia consumer advocate, who is challenging the price tag FirstEnergy has placed on the Harrison power plant.

The company filed a petition Nov. 16 for approval to purchase the 80% ownership interest currently held by Allegheny Energy Supply Co., LLC (AE Supply) in the Harrison Power Station, giving Mon Power full ownership of the 1,984 MW coal-fired generator near Clarksburg, W.Va. FirstEnergy acquired AE Supply, an unregulated generation subsidiary, in its 2011 merger with Allegheny Energy Inc.

Mon Power said it will pay the lower of market or book value for the plant. It filed a valuation by Navigant Capital Advisors estimating the fair market value of AE Supply’s interest in Harrison at $1.333 billion ($846/kW), higher than AE Supply’s $1.164 billion book value.

Byron L. Harris, director of the West Virginia Consumer Advocate Division of the Public Service Commission, said the companies’ valuation is more than double the $554 million book value AE Supply assigned to the plant two years ago.

Paid Too Much

“FirstEnergy basically paid too much for the Allegheny acquisition,” he said, noting that FE booked $800 million to goodwill in the acquisition. Harris said his office is awaiting an analysis on whether the acquisition is the best solution to Mon Power’s generation needs.

As part of the deal, AE Supply would purchase Mon Power’s 8% interest in the Pleasants Power Station, giving AE Supply full ownership of the 1,300 MW coal plant in Willow Island, WV.

The two transactions will increase Mon Power’s net installed capacity by 1,476 MW, capacity the utility says it needs to address a generation deficit identified in its 2012 Resource Plan.

Mon Power wants the commission to approve a $63.4 million annual surcharge to help fund its net $1.1 billion  investment until the Harrison plant can be included in a new base rate case.  The surcharge would boost the companies’ annual revenues by 5.5%.

The companies said residential customers using 1,000 KWh would see a net increase of less than $1 monthly because the surcharge will be partly offset by a $65.7 million rate reduction that took effect in January due to lower fuel and purchased power costs.

FERC Approval also Required

The acquisition also will face scrutiny from the Federal Energy Regulatory Commission.

The company will be required to show that the transaction will have no adverse impact on competition or result in cross-subsidization of AE Supply. Docket # EC13-43

The PSC set an April 26 deadline for filing of intervener and staff testimony and a May 17 due date for rebuttal testimony. The commission will take oral testimony May 29-31.

Hearing: Wednesday – Friday, May 29-31, 9:30 a.m., Howard M. Cunningham Hearing Room, PSC Building, 201 Brooks Street, Charleston, WV.

Posted on

Pepco Goes Back to the Well

Unhappy with a $24 million rate increase approved in September, Potomac Electric Power Company asked D.C. regulators March 8 for an additional $52.1 million in distribution revenue.

Pepco said it needs the increase because its revenues have not grown enough to support increased spending on reliability improvements. In its previous rate case, Pepco — the subject of harsh criticism over its reliability — received only $24 million of the $42 million rate it requested.

Pepco said its return on equity is only 5.8%, less than half of the rate authorized by the District’s Public Service Commission.

Insulting

D.C. People’s Counsel Sandra Mattavous-Frye had no sympathy for the company’s arguments, calling the rate request “insulting.”

The company said its request would increase the bill of a District resident using 750 KWh per month by about 6%. Mattavous-Frye noted that the request would represent a 36% increase in distribution rates.

“Before the ink is dry on Pepco’s September 2012 $24 million increase … and before anyone can validate whether we have seen even the most basic long term reliability improvements promised, the company is back seeking much, much more,” she said in a statement.

Pepco has been the target of customer ire in D.C. and Maryland as a result of frequent “blue sky” outages and its restoration efforts after the February 2010 blizzard and the June 2012 derecho. The Washington Post reported in 2010 that Pepco ranked near the bottom nationally for reliability.

Outages Down

Pepco said it has reduced outage frequency in the District by 17% and outage duration by 21% since 2010, when it began increased spending in its “Reliability Enhancement Plan.” Customers on improved feeders saw a 28% cut in outage frequency and a 42% reduction in outage duration from 2011 to 2012.

Pepco got better marks for its response to Hurricane Sandy in October — when most of the 130,000 customers who lost power were restored within 30 hours — although the storm’s path spared the service territory from the worst damage.

The company is also asking for an increase in the authorized rate of return on equity (ROE) to 10.25% from 9.5%. Pepco said the increase was necessary for it to maintain investment grade credit ratings.

Maryland Rate Case

Pepco filed a $60 million rate hike request with the Maryland Public Service Commission in November that would increase the average residential bill by $7 per month, a 5% boost. In July, the PSC rejected all but $18 million of the company’s previous $68 million rate request. The commission balked at what it called the company’s effort to increase shareholder returns “before Pepco corrects its sub-par performance.”

Posted on

OPSI Calls for Extension of PJM Monitor’s Contract

The Organization of PJM States (OPSI) asked the PJM Board of Managers March 12 to extend the current contract of Market Monitor Marketing Analytics to allow enough time to correct “the serious defects” in the board’s solicitation for a replacement.

Monitoring Analytics’ six-year contract expires in June 2014.

Edward S. Finley, OPSI president and Chairman of the North Carolina Utilities Commission said the extension was needed because there isn’t enough time to revise the board’s draft request for proposal (RFP) “given the character, number and gravity of the defects, and the need for them to be cured before requesting and obtaining FERC approval.”

OPSI’s latest letter follows a 17-page critique of the RFP that OPSI sent to the PJM board on March 4 (see previous story).

At his press conference Thursday releasing the 2012 State of the Markets report, Monitoring Analytics President Joseph Bowring said he was optimistic about his firm’s chances in the competition for a new contract. “We are confident that we are very good at market monitoring,” he said.

Asked at the press conference why the board was unwilling to renew the contract without a competition, Bowring said “I have no idea what their motivations are.”

Posted on

New Jersey Board of Public Utilities to Rule on JCPL Depreciation Study

The Board of Public Utilities is scheduled to rule March 20 on whether to compel Jersey Central Power & Light Co. to conduct a depreciation study in its pending rate request. The Division of Rate Counsel requested the analysis, noting that JCPL’s last study was conducted 17 years ago.

JCPL balked, arguing that there is no requirement that a depreciation study be filed with a base rate case. The company said its depreciation rates have been updated annually since 2000, and that its depreciation rates were reviewed in its 2002 base rate case, when a change in the depreciation methodology resulted in a decrease in the allowed depreciation expense.

The board will be ruling on whether to overturn an administrative law judge ruling rejecting the Rate Counsel request. The board agreed to review the ruling Feb. 20 “given the possible impact of the calculation of depreciation on the determination of just and reasonable rates.”

The board ordered JCPL to file the rate case in response to a Rate Counsel petition alleging the company was earning an unreasonable return on its rate base.

The company responded Nov. 30 with a request for a $31 million increase. It followed up with a supplemental request Feb. 22 seeking to recover the $630 million it spent on Hurricane Sandy. The company asked for $345 million in capital expenditures and $258 million in non-capital costs, which it proposed to recover over a six-year period. JCPL said it would continue to have the lowest residential electric rates among the states four electric distribution companies even after the rate increase, which would result in a 4.5% increase for an average residential customer. Docket Nos. ER12111052 and OAL PUC 16310-12.

Posted on

North Carolina: Progress Energy Reaches Partial Settlement in Rate Case

The North Carolina Utilities Commission will hold a hearing March 18 to consider a proposed settlement that would grant Progress Energy Carolinas an average 5.7% base rate increase.

The settlement between the company and the North Carolina Public Staff would boost rates by $151.4 million in the first year and $183 million the second year.

The increase in year two includes $31.4 million for construction of new natural gas combined-cycle generation at the Sutton Plant in Wilmington, N.C. The company has requested that new rates go into effect June 1.

The average increase is about half the 11% ($359 million) request the company had sought in a rate request filed in October. The settlement includes a return on equity (ROE) of 10.2%, down from the requested 11.25%.

The settlement did not resolve the allocation of the increase among customer classes, the company’s change to a single coincident peak cost allocation factor, or the industrial economic recovery rider proposed by the company.

The settlement is likely to be challenged by the North Carolina Attorney General, which has appealed rate settlements with Duke Energy Carolinas and Dominion North Carolina Power that included ROEs of 10.5% and 10.2% respectively. The attorney general said the regulators failed to balance the needs of the utility’s investors “against the economic conditions and returns that … customers are experiencing.”

The North Carolina Supreme Court heard oral arguments in the Duke case (# 268A12) Nov. 13. The attorney general filed its challenge to the Dominion settlement Feb. 18.

Posted on

North Carolina: Duke Energy Carolinas Seeks Energy Efficiency Rate Increase

Duke Energy Carolinas filed a request with the North Carolina Utilities Commission Wednesday for an increase in rates to cover its energy-efficiency programs. Customers using 1,000 kWh per month would see rates rise by $2.86 (residential) to $3.87 (non-residential) effective Jan. 1, 2014.

Duke asked for no change in its fuel charge. The company said the increased use of gas-fired generation and economies from the joint dispatching of Duke Energy Carolinas and Progress Energy Carolinas offset higher commodity prices. Progress will make its annual fuel and energy efficiency filings in June.

This request is separate from a proposed $446 million annual hike the company filed Feb. 5 to recover $3.8 billion in capital investments, including retirements and replacements of generation plants and transmission and distribution systems.

The capital investments include $1.5 billion for two new generating stations at Cliffside steam station, an 825 MW advanced coal-fired plant in Rutherford and Cleveland Counties and the 620 MW Dan River combined cycle natural gas plant in Rockingham County. The company also has invested $650 million in its Oconee and McGuire nuclear plants and $590 million in maintenance and upgrades to other existing generators and $722 million on its transmission and distribution systems.