Page 1570 – RTO Insider

March 24, 2015

FERC Accepts Formula Rate Protocols from MISO, SPP, PJM Utilities

The Federal Energy Regulatory Commission last week accepted revised transmission formula rate protocols by four SPP and MISO utilities that had deficient protocols.

The commission also accepted a new protocol from Louisville Gas & Electric and Kentucky Utilities, a PJM member in Kentucky and Virginia.

While accepting the filings, FERC required further compliance filings within 60 days from Black Hills Power, which serves parts of South Dakota, Wyoming and Montana; Empire District Electric Co., with territory in Missouri, Kansas, Oklahoma and Arkansas; Kansas City Power & Light and KCP&L Greater Missouri Operations, with customers in Missouri and Kansas; and Westar Energy, which serves parts of Kansas.

The commission ordered the revisions for the SPP in July 2014, saying the existing protocols had impeded the ability to review and appeal transmission owners’ cost claims. The commission ordered similar revisions for MISO transmission owners in 2013. (See FERC OKs MISO, TO Rules on Formula Rate Challenges.)

The commission found that the provisions related to rate challenge procedures and transparency in all of the filings generally comply with directives in the July 2014 orders, but they required some additional modifications.

March 24, 2015

FERC Rejects Dominion Rate Request

By Michael Brooks

The Federal Energy Regulatory Commission last week rejected Dominion Virginia Power’s request to push back the effective date for a rate revision by more than year, a change that would have cost transmission customers $11.1 million (ER15-856).

Dominion had asked FERC to change the effective date of revised transmission depreciation rates from April 1, 2013, to Jan. 1, 2012. FERC approved the revised rates last April.

FERC said changing the date would violate its rule against retroactive ratemaking, a charge the North Carolina Electric Membership Corp. made in a February protest to the request. (See NCEMC: Dominion Request is ‘Retroactive Ratemaking’.)

“The filed rate and retroactive ratemaking doctrines both bar a public utility from charging a rate other than the rate properly filed with the commission, and similarly bar the retroactive imposition of an increased rate for service already provided,” FERC said. “However, this is precisely what Dominion proposes to do in the instant filing … by now proposing to charge customers an additional $11.1 million from Jan. 1, 2012, through March 31, 2013.”

Dominion said it requested the extension because of a Virginia State Corporation Commission ruling that increased its depreciation expense and accumulated depreciation effective Jan. 1, 2012 — the date of a depreciation study commissioned by Dominion. The SCC told FERC it supported Dominion’s request, saying it is standard practice to use the date of the study as the effective date for changes in depreciation rates.

FERC responded that “we are not suggesting that a Jan. 1, 2012, effective date would be inappropriate for retail rates, which is within the purview of the states. In this case, however, Dominion will receive all of its transmission operations and maintenance expenses through its formula rate, and its allowed rate of return and associated income taxes on all unrecovered plant balances. Furthermore, the commission has previously accepted rates that reflect regulatory differences from what this commission requires for accounting purposes and what state commissions require for state rate purposes.”

March 24, 2015June 15, 2023

FERC Rejects Order 1000 Waiver on SPP-SERTP Seam

By Chris O’Malley

The Federal Energy Regulatory Commission said last week that SPP must engage in interregional coordination and cost allocation with the Southeastern Regional Transmission Process region (SERTP), rejecting the RTO’s request for a limited waiver of Order 1000 requirements.

FERC’s ruling came in a 94-page order that approved Order 1000 compliance filings by SPP and the SERTP utilities, subject to additional filings (ER13-1939).

SPP had argued its only interconnection to SERTP was via Associated Electric Cooperative Inc. (AECI), which supplies 51 local electric cooperatives in Missouri, Iowa and Oklahoma.

Because AECI is “a non-commission jurisdictional utility” that does not intend to revise its Open Access Transmission Tariff to implement Order 1000, SPP argued, it was impossible for the RTO to comply with Order 1000’s requirements regarding the SERTP seam.

A waiver is also appropriate, SPP argued, because it and AECI already engage in interregional coordination through a joint operating agreement. The two regions have been exploring revisions to the JOA to provide “similar benefits that the requirements of Order No. 1000 intend to provide,” SPP said.

FERC noted, however, that AECI voluntarily enrolled in the SERTP region. “As a result, SPP and SERTP are neighboring transmission planning regions,” the commission said.

Large Number of Interconnections

FERC also said the RTO is connected to AECI “to a greater degree than SPP suggests” because of the large number of interconnections between AECI and 10 SPP members, including Kansas City Power & Light and Westar Energy.

The commission also rejected SPP’s claim that FERC had set a precedent for its request when it granted a waiver to Maine Public Service Co. FERC noted that Maine Public Service is not interconnected to the United States but rather to Canada. That unique situation made it impossible to join a transmission planning region consistent with Order 1000.

The commission accepted interregional cost allocation filings by SERTP members Southern Co., Duke Energy Carolinas, Louisville Gas & Electric, Kentucky Utilities and Ohio Valley Electric Corp. with a few caveats.

FERC ordered the companies to provide identical language in provisions on cost allocation, data exchange and the identification of interregional transmission facilities.

March 20, 2015June 15, 2023

Protests Continue — on Camera — at FERC

By Rich Heidorn Jr.

WASHINGTON — About 10 protesters were led or carried out of the Federal Energy Regulatory Commission’s open meeting Thursday after defying the commission’s “no interruptions” rule with chants of “Stop construction at Cove Point!”

Last week, the commission issued an order saying it no longer will allow protesters to read statements before its meetings, as Chairman Cheryl LaFleur previously had permitted since the activists began appearing regularly at commission meetings last fall.

The new policy came after protesters — no longer content to read a statement before the session — disrupted January’s open meeting and a February technical conference on the Clean Power Plan. (See FERC Cracks Down on Protesters.)

Last week’s order also ended the commission’s ban on the use of cameras — which meant that the first test of the new policy was captured by photographers, including those from Politico and RTO Insider.

Protester briefly resists security guards attempting to escort him out of FERC meeting. — Ted Glick, national campaign coordinator at the Chesapeake Climate Action Network, briefly resists security guards attempting to escort him out of the FERC meeting. © RTO Insider

The commission’s secretary began the meeting by reading a summary of the new policy, which also was posted on a large sign outside the meeting room.

Immediately thereafter, two protesters stood up, facing the commissioners, but were confronted by security as they attempted to speak. One of the protesters was Ted Glick, national campaign coordinator at the Chesapeake Climate Action Network. Glick had previously said he did not think the order expressly prohibited unscheduled speakers.

As the two were being ejected, seated protesters — like the others, wearing red T-shirts with slogans such as “FERC Doesn’t Work” — took up the chant and were led from the room.

Finally, a group that had taken seats on the floor in front of the audience were forced to leave.

The commission briefly left the meeting room during the episode, which lasted for about four minutes. Security guards said later that the protesters were escorted out of the building. No one was arrested.

Over the past year, FERC has been the target of environmental activists over its approval of natural gas pipelines and export terminals, including Dominion’s Cove Point site on the Chesapeake Bay near Lusby, Md., which is now under construction.

The challenge of dealing with the protesters now falls to Commissioner Norman Bay, who is scheduled to replace LaFleur as chairman on April 15. Beyond Extreme Energy, the organization that has been coordinating the protests, said it is hoping to attract more than 500 demonstrators to FERC in May.

In November, about 100 climate change protesters blockaded FERC headquarters, snarling traffic on First St. N.E. About 25 were arrested. (See Federal Briefs.)

March 18, 2015

Exelon, Pepco Ink Deal with Md. Counties, but Critics Stand Firm – UPDATE

By Suzanne Herel

Two key Maryland counties have agreed to support Exelon’s controversial takeover of Pepco Holdings Inc. in return for promises to fund customer bill credits, grid reliability improvements, renewable energy projects, energy efficiency programs and help for low-income consumers.

Montgomery and Prince George’s counties, suburbs of D.C., represent three-quarters of Pepco’s customers in Maryland, where Attorney General Brian Frosh, consumer advocacy groups and environmentalists have been urging the Public Service Commission to reject the $6.8 billion deal. (See Exelon ups Merger Offer in Maryland as AG Calls for Rejection.)

The acquisition, which would give Exelon control of more than 80% of the state’s electricity customers, also faces opposition from detractors in D.C. (See Exelon Sweetens the Deal for DC in Pepco Takeover.)

“We believe the agreement is significant because it was signed by a large consortium of low-income consumer advocates and recreational interest groups, in addition to Montgomery and Prince George’s counties,” Exelon spokesman Paul Adams told RTO Insider.

The agreements, filed with the PSC, bring with them a delay in a decision while the public is given time to weigh in.

The parties involved can submit testimony on the settlement until March 30. This is also the deadline for testimony on another settlement with The Alliance for Solar Choice filed March 2. Written public comments may be submitted through April 9.

Hearings Set for April

Evidentiary hearings are set for April 7-9. The PSC had planned to issue its decision on April 8; now it is shooting for April 29.

In a statement announcing the new schedule, the PSC said, “According to the request, the joint applicants have entered into two settlement agreements that they believe resolve all contested issues in this proceeding.”

The Maryland Office of People’s Counsel, however, continues to urge the PSC to reject the deal.

“Generally, we disagree with that,” People’s Counsel Paula Carmody told RTO Insider on Tuesday. “Our perspective is that the transaction is not good for our state, not good for ratepayers and not in the public interest.”

Carmody noted the number of parties yet to be won over — among them the Maryland Energy Administration, the staff of the PSC and groups including the Coalition for Utility Reform.

That organization’s counsel, Montgomery County Councilmember Roger Berliner, submitted a filing March 3 asking the PSC to require Exelon to increase its commitment to reliability, renewable energy and distributed generation.

“Exelon is trying to pick folks off, but appreciate the dynamic they face,” Berliner said in an interview, echoing Carmody’s list of critics.

In a brief filed with the PSC, the OPC said, “Nothing in the revised commitments or in the joint applicants’ initial brief overcomes the substantial harms and risk that will result if the subject acquisition is approved.”

It added, “The joint applicants’ commitments that supposedly provide benefits — those concerning reliability, the Customer Investment Fund and low-income assistance — also provide little, if any, value.”

The proposed conditions, OPC said, don’t address what Maryland stakeholders will lose: “the ability and right to compare the policy proposals and performance of two investor-owned utilities serving customers in Maryland that are subject to the same laws and regulations.”

“The concern about Exelon is that it will favor its nuclear power plants at the expense of renewable energy. In the absence of Exelon making a commitment to renewable and distributed energy in Maryland, I don’t think this merger will be found in the public interest.”

‘Necessary but not Sufficient’

Berliner commended some of the settlement’s aspects, in particular Exelon’s agreement to pay $500,000 for the PSC to retain a consultant to study how to transform the electric grid; a commitment to improve reliability by 2018; and the creation of a $50 million “Green Sustainability Fund” to stimulate investment in solar, energy storage and other distributed generation.

“There are good things in the settlement with the counties,” Berliner said. “But to use legal terminology, they are necessary but not sufficient. The bar is a little higher for this merger to be found in the public interest.

“I think they need to do more.”

In the meantime, Gov. Larry Hogan has delayed the appointment of two new members of the PSC until after the five-member board rules on the Exelon deal. The governor has nominated Michael L. Higgs Jr., a telecommunications attorney, and Jeannette M. Mills, former chief customer service officer for Exelon’s Baltimore Gas and Electric.

DC Opposition

Meanwhile, three members of the D.C. Council have penned a letter to the District’s PSC urging the commission to reject the deal, saying that it is not in the public interest, as required by law.

Mary Cheh, Elissa Silverman and Charles Allen said the transaction creates a conflict of interest between Exelon, a producer of electricity, and Pepco, which buys electricity and distributes it.

“A producer looks for the highest prices for its product, but a buyer looks for the lowest prices,” they said.

They cited the commission’s 1999 approval of Pepco’s proposed divestment of its generation assets as being in the public interest and yielding “non-monetary, but no less important, benefits to District ratepayers.”

“With Pepco substantially out of the generation business,” the PSC wrote at the time, “there will be less motivation for the company to act as an inhibitor to the development of a competitive generation market in the District.”

The councilmembers concluded that “the only real beneficiaries of the takeover will be Pepco shareholders (Exelon is buying them out at a more than 24% premium over market value) and Exelon Corp. (which will capture a steady, reliable stream of revenue to offset its riskier generation assets).”

The D.C. Office of People’s Counsel, who also is critical of the proposed deal, said last week that it was too early to tell if the settlement proposed in Maryland would benefit D.C. consumers.

“At this time, the Office of People’s Counsel is focused on the evidentiary hearings” set for March 30 through April 8, People’s Counsel Sandra Mattavous-Frye said. “There may be terms in the Maryland settlement proposal that may be of benefit to District consumers, but I still need more time to carefully examine the details and to determine whether any of these have value to the District of Columbia.”

The acquisition has been approved by the staff of the Delaware PSC, the New Jersey Board of Public Utilities, the Federal Energy Regulatory Commission and the Virginia State Corporation Commission.

Exelon hopes to close the deal in the second or third quarter of this year.

March 17, 2015June 15, 2023

PJM Planning Committee Briefs

VALLEY FORGE, Pa. — Demand response forecasts used in PJM planning studies will drop in all but two of 22 transmission zones under a methodology change endorsed by the Planning Committee last week.

According to a PJM analysis, 10 zones will see drops of 25% or more for delivery year 2020, with the Dayton Power and Light (DAY) and Duquesne Light (DQE) zones falling by almost half (see chart). RTO-wide, forecast DR for delivery year 2020 would drop by one-quarter to 8,200 MW from 11,100 MW.

The current load deliverability analysis uses the amount of DR that has cleared in the last base residual auction to project DR available five years in the future. But PJM officials say that a significant amount of DR that clears the auction is replaced by other resources before the delivery year arrives. In the 2014/15 year, 46.5% of the DR assumed to be available had been replaced by non-DR resources. (See Change Proposed in PJM Demand Response Modeling.)

The new method will base future forecasts on an average of the final amount of committed DR for the most recent three years. The average would be expressed as a percentage of the zone’s 50/50 summer peak forecast for application to future years’ demand.

“All that matters in this method is what has historically committed, not what has cleared in any particular auction,” said Tom Falin, PJM manager of resource planning.

If approved by the Markets and Reliability Committee this month, PJM will begin using the new methodology in the 2015 Regional Transmission Expansion Plan.

Falin said the new method is unlikely to have much practical impact, at least in the short term.

A reduction in forecast DR will increase the assumed load of locational deliverability areas (LDAs), resulting in an equivalent increase in the LDA’s capacity emergency transfer objective (CETO) — the amount of power it must be able to import during a localized capacity emergency while remaining within a loss-of-load expectation of one event in 25 years.

Planners compare the CETO level with the LDA’s capacity emergency transfer limit (CETL), the maximum amount of power the transmission system can deliver into the LDA.

For the May 2015 capacity auction, all LDAs have CETO/CETL margins in excess of 115%, large enough that the DR forecast changes are unlikely to impact the areas’ reliability requirements.

“We seem to have very healthy CETO/CETL margins,” Falin said. “The practical impact of this change may not be all that great.”

Change Would Shift Baseline Upgrades to Network Customers

PJM wants to change how it studies long-term firm transmission service requests to ensure individual requesters share in the cost of transmission upgrades required to serve them.

PJM’s Aaron Berner told the Planning Committee on Thursday that the “pancaking” of individual requests sometimes results in a need for reinforcement projects but that the current study process results in the cost of such improvements being assessed broadly on load customers and transmission owners through baseline upgrades rather than on individual requesters through network upgrades.

Berner outlined a proposed problem statement that will be brought to a vote at next month’s committee meeting.

Changes Proposed for Light Load, Wind Modeling

PJM planners are considering lowering the light-load modeling assumption from 50% to 35% of the summer peak based on an analysis that showed a significant number of hours of lower load.

PJM’s light-load period is 1 a.m. to 5 a.m. from Nov. 1 through April 30 of each planning year. Planners said their analysis of three years of data found loads in the MAAC, ComEd and Dominion zones are only 35% of peak load during a significant number of hours.

At the same time, planners are considering increasing the maximum wind ramping from 80% to 100%, which is consistent with the modeling in its neighbor MISO. Five transmission owner zones — AEP, APS, COMED, PENELEC and PL — contain wind generation. Between 2001 and 2014, average maximum wind capacity for the five zones was 92.5%.

PJM will conduct sensitivity analyses on the proposed changes and report back to the Planning Committee. (See Light-Load Study: Generation Up, Load Down.)

PJM Seeks to Revise Definitions in Merchant Network Upgrades

PJM will seek to revise three definitions in the Tariff that it says are making it difficult to properly process requests for merchant network upgrades. Under a problem statement endorsed by the PC, PJM would consider changes to the definitions of “Upgrade Request,” “Customer-Funded Upgrade” and “Merchant Network Upgrades.”

Planners said the current definitions have sometimes resulted in higher-priority interconnection projects negating a merchant network upgrade request.

— Suzanne Herel

March 17, 2015June 15, 2023

FERC Cracks Down on Protesters

By Michael Brooks

The Federal Energy Regulatory Commission said last week it will no longer allow protesters to read statements before its open meetings.

Borrowing language from the Federal Communications Commission, FERC issued an order modifying the Code of Federal Regulations “to clarify that the term ‘observe’ does not include disruptive behavior.”

Over the past year, FERC has been the target of environmental activists over its approval of natural gas pipelines and export terminals. At the commission’s January open meeting, protesters continually interrupted Chairman Cheryl LaFleur as she tried to begin proceedings, leading her to adjourn the meeting while security cleared the floor. (See Protesters Interrupt FERC Open Meeting.) Protesters were also escorted out after disrupting a FERC technical conference on proposed carbon emission rules in February.

While LaFleur has previously allowed protesters to read statements before she begins open meetings, the new order makes it clear that this will no longer be tolerated. According to the order, “communications made or presented by unscheduled presenters will not be considered by the commission.”

One protester, Ted Glick, said FERC should have public comment periods at open meetings.

FERC is in “drastic need for some doses of reality to the impact of their decisions,” said Glick, national campaign coordinator at the Chesapeake Climate Action Network. “We think the commissioners really need to hear from the public.” He said he did not think the order expressly prohibited unscheduled speakers.

Beyond Extreme Energy, the organization that coordinated the January meeting interruptions, said it is hoping to attract more than 500 demonstrators to protests at FERC in May.

FERC also amended its rules concerning recording open meetings to allow photography, which was previously prohibited. FERC said it recognizes that its “existing regulations concerning recording open meetings are unduly complex and out of date.” It said it was adopting language used by the Consumer Product Safety Commission, which allows members of the public to record meetings as long as they remain seated.

March 17, 2015

Constitution Pipeline: Headed to Completion or to Court?

By William Opalka

Opponents of a 124-mile natural gas pipeline that would provide New York and New England access to Pennsylvania shale gas have threatened to go to court next week to force federal regulators to reconsider their approval of the project (CP13-499, CP13-502).

The proposed Constitution Pipeline won a certificate of public convenience and necessity from the Federal Energy Regulatory Commission on Dec. 2.

Stop the Pipeline, a citizens group intervening in the case, said it will go to court if FERC does not consider its request for a rehearing “on the merits” by Friday. The group is being assisted by the Pace Environmental Litigation Clinic, which lists environmentalist Robert F. Kennedy Jr. as a supervising attorney.

FERC issued a procedural order for rehearing on Jan. 27 but has not taken any further action. Pace said this amounts to a “constructive denial,” a de facto refusal to rehear the case without an actual order saying so.

Stop the Pipeline said in its request for a rehearing that the certificate of public convenience was illegally granted before the New York State Department of Environmental Conservation had issued water quality permits and before constitutional questions of affected property owners were resolved. It also said that FERC violated federal law by separating this project from other gas infrastructure projects in New York that should have been reviewed in total.

ISO-NE says inadequate natural gas infrastructure has threatened reliability and driven up power costs as New England has become increasingly reliant on gas as fuel for electric generation. The region, which now relies on gas for about half of its power generation, sees prices spike on cold days when more gas is needed for home heating and the grid operator has to turn to expensive fuel oil.

The Constitution Pipeline, which is entering the final phase of environmental reviews by New York regulators, would start in Susquehanna County, Pa., and travel northeast through New York, where it would connect with the Tennessee Gas and Iroquois Gas pipelines.

Kinder Morgan’s Tennessee pipeline is a major east-west natural gas artery that supplies Texas and Gulf Coast gas to upstate New York and New England.

The Iroquois pipeline heads to the southeast, serving New York City and its environs. An expanded compressor would be added by Iroquois in nearby Wright, N.Y., at the terminus of the Constitution line.

Constitution’s path includes a section of New York that has its own potential for fracked shale gas. However, in December, New York Gov. Andrew Cuomo effectively banned the practice due to health concerns. (See Cuomo Bans Fracking in New York.)

Williams, Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings are partners in the Constitution project.

“There is this supply of stranded gas that is needed in New England that can’t get there because the infrastructure hasn’t kept up,” said Christopher Stockton, a spokesman for Constitution. If permits are granted, construction would start this summer and take about a year, with the pipeline in operation by mid- to late 2016.

He added that the Pennsylvania supply, closer to where it is ultimately used, would cut fuel costs by half. Most of the natural gas currently used in New York and New England originates in the Gulf Coast and Texas.

The Constitution project is now before the New York DEC, where an extended comment period ended in late February. Opponents said they delivered 5,000 comments to the department office in Albany on the final day and now believe the project is in trouble.

DEC permits and approvals are required for construction and operation of the pipeline. Additional permits from the U.S. Army Corps of Engineers and the U.S. Fish and Wildlife Service are also pending.

The 30-inch pipeline would deliver 650,000 dekatherms of gas per day. The pipeline was first proposed in April 2012.

This pipeline is essentially parallel to the New York section of Kinder Morgan’s proposed Northeast Energy Direct pipeline. The Kinder Morgan project is two years behind Constitution in the regulatory and planning cycle, with proposed operations in 2018.

March 17, 2015June 15, 2023

Developers Lament Lack of Tx Competition, Interregional Projects under Order 1000

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — The Federal Energy Regulatory Commission needs to do more to ensure Order 1000 opens transmission development to competition and results in interregional projects, developers said last week.

“FERC needs to go back to the drawing board,” Kristine Schmidt, vice president of regulated development for ITC Holdings, told Infocast’s 18th annual Transmission Summit, which drew more than 80 industry officials over three days. (Presentations from the conference are available here.)

Schmidt, a one-time aide to former FERC Commissioner Nora Mead Brownell, said Order 1000’s intent has been “watered down” since former Chairman Jon Wellinghoff left the commission in 2013, as a result of compromises to accommodate regional differences and “carve outs” on the original order’s prohibition against transmission owners’ rights of first refusal (ROFRs).

Schmidt said that while competition may eventually take hold as it did for independent power producers under FERC Orders 888 and 890, “we’re far away from that” now.

Randy Satterfield, executive vice president for Duke-American Transmission Co., agreed. “ROFR laws are in the way,” he said. “That has to be taken care of through FERC or the courts.”

Last May, FERC ruled that transmission planners may exclude consideration of non-incumbent proposals on projects subject to state ROFRs. FERC had previously required transmission providers to remove from commission-approved tariffs and agreements ROFRs giving incumbent utilities preferences to build transmission facilities selected in the regional transmission plan.

The commission ruled 3-1 that its previous position would require planners to evaluate non-incumbent proposals that had no chance of getting built because of state rules assigning them to incumbent utilities. (See Order 1000 Reversal: Reality Check or Surrender to Incumbents?)

‘Evolution’ in the RTOs

Satterfield said “the process is still evolving,” noting that while PJM has opened several “windows” for competitive proposals, SPP hasn’t identified any projects for competition and MISO has said it doesn’t expect to open any windows before 2016 at the earliest.

“So we’re being held back in that the opportunities in some of the RTOs are not yet there,” he said. He said that his company is “doing a fair amount of work in California,” which he said is “leading the pack.”

Although FERC has approved RTOs’ Order 1000 regional planning and cost allocation rules, “there’s still things that need to be buttoned up and tightened down” to ensure fair competitive processes, said Todd Fridley, vice president of Transource Energy. “We in the industry understand there will be growing pains as the market emerges.”

Schmidt said SPP made a wise decision in appointing an independent panel to judge competitive proposals and not leaving it to RTO planning staff, as in PJM. The panel’s recommendation would be submitted to SPP’s board of directors for review and approval.

“The RTOs were never formed to be the ones to choose winners and losers,” she said, adding, “RTOs have a long way to go to prove they have the discipline to evaluate proposals.”

Artificial Island

PJM’s April 2013 solicitation for a fix for stability problems at Artificial Island has proven a cautionary tale.

RTO planners recommended the selection of Public Service Electric and Gas last June. But objections by environmentalists and disappointed bidders led the PJM board to reopen the competition to four finalists. With the process still incomplete, PSE&G is now fighting PJM before FERC. (See related story, PJM: PSE&G’s Remedy for Artificial Island Bid Process ‘Draconian,’ ‘Self-Serving‘.)

“It’s not ideal. This is PJM’s first attempt at this,” said R. Mihai Cosman, a principal in Exelon’s corporate transmission development unit. “They’re trying to do the right thing. We in the future will have some sort of a standard process.”

Robert Daileder, a partner in law firm Nixon Peabody, said the unwieldy solicitation increased costs for competitors. “At the end of the day, the [winner] will probably be the best project … but the process may be much more expensive than anybody anticipated because of the changing goalposts,” he said.

“I think PJM has learned that maybe they didn’t scope it tightly enough,” said James Nicholas, who specializes in siting and licensing for CH2M Hill, an environmental and engineering consulting firm.

Interregional Projects

Developers also criticized the lack of interregional projects under Order 1000. The order requires transmission providers only to “consider” whether the needs identified in their local and regional transmission plans could be addressed most cost-effectively through joint projects with a neighboring region.

Satterfield said another obstacle to interregional projects is the disparities in competitive processes and cost allocation between regions.

“There can be great projects that cross seams and right now there is not a way to ensure those projects can proceed,” he said. “That’s got to get fixed.”

Schmidt said SPP’s northern expansion to Canada means its seam with MISO is growing. “It’s costing us a lot of money not having these projects on the table,” she said.

“Order 1000 did no favors to interregional planning. In fact, it’s not interregional planning, it’s interregional coordination,” said George Dawe, vice president of Duke-American Transmission Co.

“The RTOs, frankly, are doing what they’ve been required to do,” which is sharing information. He said the RTOs are conducting “quick-hit” studies that are not resulting in actionable projects.

Diana Rivera, director of market development and regulatory affairs for Clean Line Energy Partners, said interregional coordination is only occurring between neighboring regions, with much of the focus on seams issues. “Transmission needs that are broader in scope, like how do we move renewables to market, are not being addressed by interregional planning or cost allocation processes,” she said.

Brian Thumm, director of planning for ITC Holdings, compared Order 1000 to Aesop’s fable “The Monkeys and Their Mother,” in which the mother accidentally smothers one of her sons due to overly nurturing it.

The moral of the story is “The best intentions will not always ensure success.”

“I can think of no greater paradigm for what I’ve seen in the planning processes than to say that the best intentions of the industry have not guaranteed success in anything that we’ve done with respect to Order 1000,” Thumm said.

March 17, 2015June 15, 2023

PJM Reducing Transmission Spending by $3.2B

By Rich Heidorn Jr.

Flat load growth, the lapse in federal subsidies for wind generators and a slowdown in coal plant retirements have caused PJM to reduce its transmission construction plans by $3.2 billion.

pjm — Generator deactivations announced in 2014 (left) and selected baseline upgrades driven by retirements (right).

PJM’s 2014 Regional Transmission Expansion Plan report, released last week, provides details of the $1.7 billion in transmission projects approved by PJM’s Board of Managers. The board approved 197 baseline projects totaling $1.1 billion and 148 network upgrades to address reliability criteria violations at a cost of $605 million.

But these new projects were more than offset by the removal of 651 network upgrades totaling $4.7 billion and 40 baseline projects estimated at $177 million, resulting in a net reduction of $3.2 billion from the spending anticipated at the end of 2013.

Generation Withdrawals

PJM said the network upgrade cancellations resulted from the withdrawal of 212 generation interconnection requests totaling 15,302 MW, one-quarter of them for wind turbines.

Generation withdrawals can reflect developers’ response to capacity auction prices. PJM also took note of the boom-bust cycle of wind development, based on the availability of the federal Production Tax Credit. The most recent iteration of the PTC covered only projects under construction by the end of 2014.

Network upgrades allow customers to interconnect to the PJM grid and obtain capacity rights. Such upgrades are recommended to the PJM board based on system impact studies, after developers receive facility study agreements.

Slowdown in Retirements

Baseline upgrades include both market efficiency projects to reduce congestion and reliability projects needed to correct violations, such as those identified in thermal and voltage analyses.

PJM said the reduction in baseline upgrades reflects flat load growth and a slowdown — perhaps temporary — in retirements of coal-fired generation. The RTO received 31 generator deactivation requests in 2014, totaling about 4,300 MW, down from 14,444 MW in 2012 and 7,745 MW in 2013.

The retirements were largely driven by the Environmental Protection Agency’s Mercury and Air Toxics Standards, which take effect this year. PJM has begun analyzing the impact of EPA’s proposed limits on generator CO₂ emissions, which are expected to create a new wave of retirements. (See related story in PJM Transmission Expansion Advisory Committee Briefs.)

The 2014 RTEP includes 27 transmission upgrades in PJM’s Mid-Atlantic and Western regions to address retirements. The upgrades include both new and upgraded transmission lines, transformers, shunt capacitors and substation improvements.

Since 1999, PJM’s board has approved almost $25.7 billion in transmission projects, including $21.5 billion of baseline transmission upgrades and $4.1 billion in facilities needed to connect more than 60,000 MW of new generation. Almost $10 billion of those projects are in service with an additional $4.2 billion under construction.