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November 5, 2024

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Delmarva Power Seeks $65 Million in Rate Increases

Delmarva Power & Light Co. filed rate hike requests totaling almost $65 million in Delaware and Maryland, saying its revenues have not kept pace with growing capital spending.

Delmarva asked for a $42 million annual increase in its electric distribution rates in Delaware, where it serves 300,000 customers, and $22.7 million in Maryland, where it serves 200,000.

Delaware Filing

Delmarva’s March 22 filing with the Delaware Public Service Commission said its current return on equity is only 6.6%, below the 9.75% ROE approved by the commission in its 2011 rate case, which boosted revenues by $22 million annually. The company is seeking a 10.25% ROE and a 7.38% increase in total revenue.

The company said the biggest driver in its rising costs is its capital spending. It expects to spend about $397 million on capital projects in 2013 through 2017, much of it for reliability upgrades. “Delmarva is not realizing sufficient growth in the number of customers and load served to offset this pace of investment,” the company said. It requested new rates take effect May 21. DE PSC Docket No. 13-115

Maryland Filing

In its March 29 filing with the Maryland Public Service Commission, the company requested a 10.25% ROE, saying it was currently earning only 7%.

The company said it spent almost $54 million on reliability improvements in 2012, with plans for an additional $115 million in 2013 and 2014. The spending helped reduced the frequency of outages by 9% and their duration by 17% since 2010, the company said.

The requested base rate increase would boost the monthly bill for a residential customer using 1,000 kWh by $7.74.

Resiliency Surcharge

In addition, Delmarva asked Maryland regulators for a three-year “grid resiliency” surcharge that would add another $1.06 to the typical customer’s bill in 2014 and allow the company to accelerate its infrastructure spending. The proposed surcharge would provide the company incentives for reaching reliability benchmarks and penalties if it failed to do so, as recommended by a September 2012 task force report prepared for Gov. Martin O’Malley. MD PSC Case # 9317

Delmarva is a subsidiary of Pepco Holdings Inc., which is also seeking a $60 million rate increase in Maryland and a $52.1 million boost in Washington, D.C. and. (See story “Pepco Goes Back to the Well“.)

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MDPSC Upholds PJM Membership Billing

The Maryland Public Service Commission upheld an administrative law judge ruling allowing Williamsport, Md., to pass through to ratepayers PJM’s annual $5,000 membership fee.

The commission ruled March 18 that the fee is part of the cost of purchased power because the town is required to be a PJM member to buy power on the wholesale market. The town purchases power from Allegheny Energy Supply Co. for distribution to town residents. The Office of People’s Counsel challenged inclusion of the fee in the town’s Power Cost Adjustment, saying it should be requested as part of Williamsport’s next base rate proceeding.

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Pa. Lawmakers Push Gas Pipeline Expansion

Senate Majority Leader Dominic Pileggi and Sen. Gene Yaw announced legislation March 26 to increase the availability of natural gas to homes and businesses.

Yaw, who represents a rural district in north central Pennsylvania, said only half of Pennsylvania homes are heated with natural gas. “We’re sitting on one of the largest deposits of natural gas in the world and don’t have access to it,” he said at a press conference.

Senate Bill 738 would require all natural gas distribution utilities  to submit reports to the Pennsylvania Public Utility Commission outlining their plans for pipeline extension and expansion projects. The bill also would expedite such projects if an economic development agency or a large number of customers want natural gas service.

Senate Bill 739 would provide $15 million in grants to schools, hospitals and businesses to fund up to half of the cost of extension projects.

More from the Lock Haven Express.

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“Black Liquor” Bill Fails in Md.

The Maryland legislature Friday, March 29 rejected a bill that would have removed so-called “black liquor,” a paper mill byproduct, from qualifying as a renewable fuel. The bill, which had passed the Senate easily, failed in a House committee in the face of lobbying by labor unions and paper companies.

The state’s renewable portfolio standard requires Maryland utilities to generate increasing amounts of electricity from renewable sources or purchase renewable credits from other companies doing so. The Washington Post reported that most of the payments for credits have been going not to wind or solar projects but to seven paper mills that use black liquor as fuel. More in The Washington Post.

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Business Practices to Get MRC Review

Business practice documents will be reviewed by the Markets and Reliability Committee in the future under a manual change approved March 28 by the Members Committee.

PJM’s business practices and implementation documents spell out its rules regarding transmission service and energy scheduling in greater detail than the manuals or tariff. Because all manual changes are already reviewed by senior stakeholder committees, some members thought business practices also should be subject to member ratification.

The change, which was approved without opposition, will require revisions to Manual 34: Stakeholder Process.

The Members Committee approves changes to Manual 34 and Manual 15: Cost Development. MRC has authority to approve all other manuals.

PJM contact: Rich Souder

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MRC First Readings

The Markets and Reliability Committee heard first readings of the issues listed below. The committee will be asked for its endorsement at its next meeting.

Capital Cost Recovery for Black Start Generators

Transmission operators providing cranking paths for black start generators would recover capital costs over five years under a proposal presented by the System Restoration Strategy Task Force. The task force rejected an alternate proposal that would have extended capital recovery over the entire asset life.

Task force chair Chantal Hendrzak said the change is needed to coincide with a provision approved by MRC February 28 allowing generators to provide black start capability outside their own zones.

The task force also will draft for MRC consideration a revised charter allowing it to broaden its consideration of black start unit compensation, including incentives based on capability and performance (e.g., fast-starting units).

Representatives of American Electric Power, Exelon Corp. and Pepco Holdings Inc. voiced support for an expanded charter at Thursday’s meeting.

But Bill Schofield, representative for the PJM Public Power Coalition, said stakeholders should wait to evaluate the impact of the initiatives approved in February before considering further revisions. “It’s premature to discuss compensation changes,” Schofield said. “It’s solving a problem we don’t know exists.”

PJM Contact: Chantal Hendrzak

Provision of E-Tag Data

PJM will make revisions to the confidentiality provisions of its tariff to comply with FERC Order 771,  requiring provision of E-Tag data to Independent System Operators, Market Monitoring Units and FERC.

E-tags are used to schedule the transmission of electric power interchange transactions. FERC said the data will help it and the regions in their efforts to police market manipulation and monitor market
efficiency.

Market Monitor Joseph Bowring welcomed the change, though he said FERC should have gone further and required provision of actual flow data.

PJM Contact: Jacqulynn Hugee

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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.

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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.

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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.

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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.

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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.