Page 1534 – RTO Insider

July 21, 2015

FERC Rejects Bid to Broaden Scope of Gas-Electric Info Sharing

By Suzanne Herel

Federal regulators last week rejected a request by a natural gas distributor to relax restrictions on its sharing of non-public information received from electric utilities.

The Federal Energy Regulatory Commission dismissed National Fuel Gas Distribution’s request in two rulings. In one, FERC dismissed the company’s request for clarification on communication allowed under Order 787, saying it was beyond the purview of its rulemaking (RM13-17-002). The other rejected NFG’s rehearing request on rules adopted by PJM under the order (ER14-1469-002).

With Order 787, the commission in 2013 opened up the sharing of non-public operational information between interstate natural gas pipelines and public utilities, saying that increased coordination would benefit reliability. (See Talk among Yourselves: FERC Urges Gas-Electric Coordination.)

Impact on Local Distribution Companies

It did not codify, however, how utilities could share such information with local distribution companies, leaving the issue to RTOs and ISOs to address individually through tariff changes. Subsequently, FERC received filings from PJM and NYISO amending their rules. (See FERC OKs Gas-Electric Talk.)

NFG is an LDC serving western New York and northwestern Pennsylvania.

FERC ultimately approved a PJM Operating Agreement change requiring LDCs and intrastate pipeline operators to promise not to disclose non-public, operational information received from PJM to third parties “or in an unduly discriminatory or preferential manner or to the detriment of any natural gas or electric market.” It also barred sharing of the information through a “conduit.”

No intervenors opposed PJM’s proposal, which was approved by FERC in July. But a month later, NFG came forward to say that a blanket restriction forbidding LDCs from disclosing such information to any third party “may inhibit appropriate sharing of operational data and discourage LDCs and intrastate pipelines from maximizing use of the data to improve reliability.”

It pointed out that “third parties” would include pipelines already qualified to receive information under Order 787 and others with whom LDCs need to coordinate to increase reliability.

For example, it said, if an expected increase in a generator’s use of natural gas in one part of the pipeline could affect a load pocket of the LDC, the company would want to be able to warn large customers in that area of an imminent capacity constraint.

NFG also took issue with the notion of requiring LDCs to guarantee their use of data would not be “to the detriment of any natural gas or electric market,” contending that “changing capacity use inevitably affects some retail customers negatively just as changing upstream supplies may affect market participants negatively.”

‘Very Broad’

In denying NFG’s request, FERC said it intentionally made the scope of information-sharing under Order 787 “very broad.” Quoting from the order, FERC added, “The commission is intentionally permitting the communication of a broad range of non-public, operational information to provide flexibility to individual transmission operators, who have the most insight and knowledge of their systems, to share that information [that] they deem necessary to promote reliable service on their system.”

It said that the potential for competitive harm under that broad scope warranted limiting it with a blanket authorization.

When Order 787 was announced, several commenters called the no-conduit rule too restrictive and offered modifications, including exclusions from the third-party restriction. FERC denied those requests.

“PJM states that it intended its restrictions on LDCs and intrastate pipelines to be an extension of the commission’s no-conduit rule to non-FERC jurisdictional facilities, applied in a manner that mimics, as closely as possible, those restrictions,” it said.

‘Untimely’

As for NFG’s request for a rehearing, FERC determined it “untimely and thus statutorily barred.”

It also noted that nothing in PJM’s Tariff precluded NFG or any other entity from sharing non-specific information needed to ensure the reliability of system operations.

“As long as NFG Distribution does not reveal, directly or indirectly, the non-public, operational information shared by PJM (e.g., information concerning a particular electric generator), NFG Distribution can request or direct its customers and operational counterparties to perform specific actions based on such information,” it said.

July 21, 2015June 15, 2023

Talen Entering NYISO in $1.2B Deal

By Rich Heidorn Jr.

Talen Energy announced its first post-spinoff acquisition Monday, agreeing to spend $1.175 billion to purchase 2,500 MW of combined-cycle generation that expands the company’s presence in ISO-NE and marks its entry into NYISO.

The company, which completed its spinoff from PPL and Riverstone Holdings on June 1, announced it will acquire three generators from MACH Gen: the 1,080-MW New Athens plant in Athens, N.Y.; the 360-MW Millennium plant in Charlton, Mass.; and the 1,092-MW New Harquahala plant near Tonopah, Ariz.

The key to the deal for Talen is the two plants in NYISO and ISO-NE, regions in which the company had previously said it was setting its sights. The acquisition will increase its geographic diversity, reducing PJM’s share of its fleet from 83% to 71% while doubling ISO-NE’s share to 2%.

It also reduces its dependence on coal and nuclear power, with coal’s share of the fleet dropping from 40% to 34% while natural gas increases from 22% to 33%.

All of those numbers will change as a result of the company’s need to divest 1,300 MW to meet market power concerns. Pre-divestiture, the company’s fleet would total 17,600 MW. (See PPL, Riverstone Accept FERC Mitigation Plan on Talen Spinoff.)

Immediately Accretive

Talen said the acquisition brings substantial tax benefits and will be immediately accretive to earnings despite poor “market dynamics” that have limited the Arizona plant to less than a 20% capacity factor, resulting in losses. All three plants are powered by Siemens 501G engines installed between 2001 and 2004.

Talen also said it expects the economics of the Athens plant to improve with the completion of pipelines that will give the plant access to low-cost Marcellus shale gas and electric transmission improvements expected to reduce congestion in NYISO’s Zones F and G.

‘Powder’ for Future Deals

Importantly, said CEO Paul Farr, the deal will retain flexibility to make additional acquisitions. “We still have dry powder given the mitigation process underway,” Farr said in a conference call with stock analysts.

The purchase will be financed with a combination of debt and cash but the precise mix would depend on interest rates and the status of its divestiture efforts, Talen said. The company said earlier this month that it had a $1 billion “war chest” for future acquisitions.

The company is believed to be considering the acquisition of American Electric Power’s merchant fleet in Ohio and Indiana, which AEP announced in January it was putting on the block. (See AEP Considering Sale of 8,000 MW in Ohio, Indiana.)

UBS Investment Research says there is a 50% probability Talen will purchase AEP’s assets. It said Talen could swallow AEP’s assets even after the MACH Gen deal because an AEP deal is not likely to occur until late 2015 or early 2016 because of pending Ohio regulatory proceedings.

Arizona Plant a Throw-In

It appears that taking on the money-losing Arizona plant was a condition for acquiring the assets Talen did want. Talen, which has no other assets in the region, said it may move the plant elsewhere or sell it for parts.

MACH Gen, which was owned by affiliates of Credit Suisse Group and Bank of America among others, filed for Chapter 11 bankruptcy protection in March 2014, saying it had assets of $750 million and liabilities of $1.6 billion. The company said it had a net loss of $120 million on $350 million in operating revenue in 2013.

The company said the Federal Energy Regulatory Commission’s rejection of its plan to sell the Harquahala plant had undermined its efforts to cut its debt. FERC said the sale — to investors that also owned two of the four natural gas generating units in Gila Bend, Ariz. — would have harmed competition within the Arizona Public Service balancing authority area (EC13-11).

The company said most of its creditors had agreed to a prepackaged reorganization that would give its second-lien debt holders 93.5% of the restructured company and reduce about $1 billion of debt. FERC approved the restructuring in April 2014 (EC14-46).

July 21, 2015June 15, 2023

FERC Rejects Rehearing on SPP Congestion Rights

By Tom Kleckner

The Federal Energy Regulatory Commission last week rejected multiple requests for rehearing of its October 2014 order finding fault with SPP’s interpretation of long-term congestion rights (LTCRs).

SPP had joined with Kansas City Power & Light to request a rehearing in November. Also requesting rehearing were five transmission-dependent utilities.

FERC did conditionally accept SPP’s January compliance filing, saying the RTO had partially complied with the October order (ER14-2553).

In the October order, FERC ruled that SPP’s response to Order 681 did not meet the order’s requirement that long-term transmission rights made feasible by transmission upgrades or expansions must be available to any party that pays for the improvements under prevailing cost-allocation methods.

The commission said SPP’s proposal did not grant LTCRs to “‘any party’ that funds upgrades,” but instead awarded transmission-service revenue credits, “which are only available to transmission service customers and are not based on the value of congestion revenue.”

FERC also found SPP’s filing did not fully comply with Order 681’s requirement that load-serving entities have priority over non-LSEs in the allocation of long-term firm transmission rights supported by existing capacity.

No Opportunity for Profit

In denying SPP’s request for rehearing, the commission said it disagreed with the RTO’s contention that Attachment Z2 credits are “reasonable equivalents to LTCRs for financial entities.”

“SPP’s Attachment Z2 crediting process awards transmission service revenue credits up to the cost of the facility, but the value of a LTCR could exceed the cost of the facility,” FERC said. “Z2 credits up to the cost of the facility may be a reasonable incentive for some market participants to sponsor upgrades … However, the Attachment Z2 credits would not serve as an incentive for financial entities that fund transmission projects to sponsor any upgrades because the most they could receive is their initial investment with no opportunity to make a profit.”

The commission also denied SPP and KCP&L’s claims that the October 2014 order questioned the justness and reasonableness of Attachment Z2. “SPP’s decision to use tariff language that already existed in a prior context” to satisfy Order 681’s requirements, FERC said, did not absolve the commission of its responsibility to determine whether the proposed language is just and reasonable.

FERC also denied a rehearing request by the City of Independence, Kansas Power Pool, Missouri Joint Municipal Electric Utility Commission, Missouri River Energy Services and West Texas Municipal Power Agency (filing as TDU Intervenors).

The group expressed concern that adoption of a nomination process will not ensure LSEs obtain sufficient LTCRs. The commission said that SPP’s use of a nomination process before the simultaneous feasibility test “addresses TDU Intervenors’ concerns and render their proposed revisions unnecessary.”

The commission added that the intervenors failed to demonstrate how SPP’s process would result in their being unable to nominate LTCRs at a level equal to their “reasonable needs.”

Compliance Filing

Boston Energy Trading and Marketing protested SPP’s proposal to provide incremental LTCRs, in lieu of revenue credits, to entities that fund upgrades. SPP proposed network upgrades costs of $5 million or more be compensated with candidate incremental LTCRs, if elected, but Boston Energy said that inclusion is contrary to Order 681 and more restrictive than other ISOs and RTOs.

FERC conditionally accepted SPP’s proposal for awarding incremental LTCRs but required it to remove the $5 million threshold.

FERC also directed SPP to separate the provision of incremental LTCRs from the proposed nomination process and to establish a new process providing incremental LTCRs when the sponsored upgrade goes into service. The commission also asked SPP to inform FERC whether the LTCRs’ initial allocation will be implemented in the 2016 ARR/TCR year, and to explain how its process will treat the provision of LTCRs and incremental LTCRs for network upgrades funded through a combination of rolled-in transmission rates and directly assigned charges.

The American Wind Energy Association and the Wind Coalition had requested clarification on how the LTCR process will affect future transmission in the RTO’s planning and interconnection processes. They also requested clarification on how incremental LTCRs resulting from transmission capacity created by upgrade sponsors would impact transmission service customers.

FERC responded by saying SPP’s compliance filing showed its transmission-planning process “ensures the continued long-term feasibility of awarded LTCRs and incremental LTCRs, and therefore has complied with the transmission planning and expansion requirements of Order 681.”

July 21, 2015

‘Shared Renewables’ Approved in New York

By William Opalka

The New York Public Service Commission on Thursday approved rules designed to allow low- and moderate-income apartment dwellers to own renewable energy projects (15-E-0082).

New York PSC Bars Utility Ownership of Distributed Energy Resources.)

“Shared Renewables places customers who do not own homes on an equal footing with traditional single-home customers and creates opportunities for low- and moderate-income families who don’t have access to electricity generated from renewable resources,” PSC Chair Audrey Zibelman said.

Customers can band together to form larger groups that share in the benefits of renewable energy projects, such as solar energy installations and wind farms.

The plan contemplates “community solar” projects, where solar panels are erected on a shared site, such as a vacant lot, with the economic benefits shared among its participants.

Under the first phase of the program, from Oct. 19 through April 30, 2016, projects will be limited to those that site distributed generation in areas where it can provide the greatest benefits to the power grid or support economically distressed communities (at least 20% participation by low- and moderate-income customers).

A second phase beginning May 1, 2016, will make shared renewable projects available throughout entire utility service territories.

The program was proposed in Gov. Andrew Cuomo’s 2015 State of Opportunity Agenda. “This program is about protecting the environment and ensuring that all New Yorkers, regardless of their zip code or income, have the opportunity to access clean and affordable power,” he said.

July 21, 2015June 15, 2023

FERC OKs MISO Tariff Change on Remote Network Loads

By Chris O’Malley

MISO has won approval to revise its Tariff to provide common treatment for network customers seeking to serve network load not physically interconnected with the RTO.

The tariff mechanism sought by MISO and approved by the Federal Energy Regulatory Commission last week is expected to eliminate the need for filing specific non-confirming network integration transmission service agreements on a case-by-case basis (ER15-1745).

The change stems from two non-conforming NITS requests: a 2013 request to allow South Mississippi Electric Power Association to take network service to serve a network load pseudo-tied to SMEPA but not physically interconnected with a transmission owner or independent transmission company within MISO (ER13-2008), and a 2014 MISO request to allow Arkansas Electric Cooperative Corp. a similar right to serve pseudo-tied load (ER14-684).

A pseudo-tie is a mechanism for operationally transferring a resource from the balancing authority in which it is physically located to another BA, which becomes responsible for it for system reliability.

Some MISO transmission owners filed comments in those cases, raising concerns that the two utilities could be receiving special treatment. The transmission owners asked FERC to order MISO come up with a global solution to the issue through changes to its Tariff.

In response, FERC said it expected MISO to offer non-conforming service on a non-discriminatory basis to other transmission customers in similar situations.

After discussions with transmission operators, MISO proposed several changes to Section 31.3 of its Tariff, which required that network load be physically interconnected with a MISO transmission owner or independent transmission company.

The revised Tariff requires that the non-interconnected network load “be part of a pricing zone in MISO, so that the network customer is subject to a rate for network service.”

One way to meet such eligibility requirements is if a non-interconnected network load is pseudo-tied into the MISO balancing authority. MISO stated that provision is necessary because otherwise there wouldn’t be a mechanism to charge the network customer for network service, “meaning the network customer could receive this service for free.”

MISO noted that in its NITS agreements with SMEPA and AECC, it required them to pay a rate for network service based on the MISO zone in which the physically interconnected portion of their load is located.

The revised Tariff also requires network customers to have coordinating arrangements in place with the host transmission owner or independent transco for reporting network load.

The revisions are effective July 19.

July 21, 2015

FERC Asked to Determine ISO-NE Winter Reliability Program

By William Opalka

Unable to reach consensus on a winter reliability program, ISO-NE and the New England Power Pool have asked federal regulators to choose between competing proposals in a “jump ball” proceeding that would cover the next three winters (ER15-2208).

The proposals were filed Thursday with the Federal Energy Regulatory Commission in an attempt to break a logjam that even a commission order couldn’t weaken. (See FERC Orders Market-Based Reliability Program Next Winter in ISO-NE.)

ISO-NE has used a winter reliability program for the past two winters to create incentives for generators to secure fuel supplies during cold months until its Pay-for-Performance program, already approved by FERC, launches in late 2018 (ER14-1050).

Both ISO-NE and NEPOOL have proposed expansions of last winter’s program, but neither has received adequate support among stakeholders.

“Both proposals are intended to address the well-documented reliability challenges created by New England’s increased reliance on natural gas-fueled generation. Both are also intended to be stop-gap measures until revised incentives for capacity resources become fully effective in 2018,” the filing states.

The primary difference between the two proposals is what types of resources are eligible to receive compensation. NEPOOL’s proposal is based on the design of last winter’s program, which provided compensation for unused oil or liquefied natural gas remaining at the end of the winter and adds demand response.

ISO-NE’s proposal includes compensation for unused oil or LNG fuel and would also compensate nuclear, hydro, biomass and coal-fired resources but does not include DR.

FERC had ordered the RTO to develop a market-based approach for the 2015-2016 season in response to a complaint by the New England Power Generators Association. The commission in April reversed course when it determined the plan might not be finalized in time. (See FERC Backtracks from ISO-NE Winter Reliability Order.) It directed the RTO and its stakeholders to keep trying to develop a solution.

The petition asks FERC for an effective date for next winter’s program of Sept. 14.

July 15, 2015

FERC Rejects Ginna Jurisdiction Challenge

By William Opalka

The Federal Energy Regulatory Commission reaffirmed its authority Monday to regulate New York reliability support services agreements, rejecting a rehearing petition filed by the state Public Service Commission challenging its jurisdiction (ER15-1047).

The NYPSC had argued that it had sole jurisdiction over the rates and terms of an RSSA it had ordered between Exelon’s troubled R.E. Ginna nuclear plant and Rochester Gas & Electric. (See NYPSC Challenges FERC Jurisdiction over Ginna.) FERC in April rejected the proposed rate schedule in the agreement and ordered hearing and settlement proceedings.

FERC rejected the contention that it would be setting retail rates, asserting that it was properly exercising its authority under the Federal Power Act to regulate wholesale markets.

“Preventing the exercise of market power through [reliability-must-run] agreements is important to ensure that wholesale rates are just and reasonable,” FERC said. “Therefore, finding that the commission does not have authority to regulate such agreements — which keep RMR resources online, provide them out-of-market compensation and remedy a potential opportunity to exercise market power — would be inconsistent with the congressional intent behind the FPA.”

The agreement, set to be retroactive to April 1 once approved, would cost about $175 million a year and be effective through late 2018. Ginna says it lost more than $150 million between 2011 and 2013.

FERC did, however, reverse its stance from April when it said it would not consider the issue of Ginna “toggling” between the RSSA and NYISO. In its original order, the commission said it would only reconsider how much Ginna would have to repay in the event the plant returned to the market after the agreement’s expiration — saying that this provision was “a sufficient disincentive” to prevent toggling. (See FERC Rejects Ginna Rates, Orders Settlement Proceeding.)

“We find that the pleadings raise disputed issues of material fact concerning Ginna’s incentive to toggle between RSSA compensation and the NYISO markets,” FERC said. That issue has been added to the roster of items to be decided in the ongoing proceeding before a FERC administrative law judge.

In Monday’s order, FERC also rejected rehearing requests from several parties that challenged several aspects of the agreement. The commission

Again accepted the NYISO Ginna Reliability Study that justified the RSSA;
Upheld the September 2018 end date for the RSSA, saying early termination clauses in the contract are consistent with FERC policy to keep RMRs of limited duration; and
Reiterated its stance that consideration of the “price-suppressive” effects Ginna’s contract would have on the capacity market is beyond the scope of the proceeding.

Meanwhile …

In the concurrent proceeding before the administrative law judges of the NYPSC, RG&E last month requested a temporary rate surcharge to avoid rate compression over a shorter duration of the RSSA. Whatever rate increases it will eventually collect are being held in abeyance until the RSSA is approved by state and federal regulators.

RG&E estimates that its deferred collection will reach approximately $25 million from the effective date of the RSSA through July and will continue to grow, with interest. “By authorizing a temporary rate surcharge, the bill impacts resulting from the deferred collection amount would be mitigated,” it wrote.

In a brief filed Monday, RG&E said the commission “should find that the company’s proposed temporary rate surcharge tariffs are in the public interest and authorize the company to immediately implement the surcharges, subject to refund.”

PSC staff filed a brief Monday that supports the move, proposing Sept. 1 as the effective date.

The Utility Intervention Unit of the state Division of Consumer Protection, a coalition of consumer and clean energy advocates and commercial and industrial users, opposed the move, calling the dollar amounts RG&E cites as “hypothetical.”

“The RSSA is not in effect,” the state consumer advocate wrote. “Neither the commission nor FERC have reached a final conclusion to accept the RSSA, so RG&E has not, and might never, incur any financial obligations to Ginna under the RSSA.”

The administrative law judges said they will set a schedule to recommend a decision once reply briefs due July 20 are filed.

July 13, 2015

REV Proposals Seek to Increase Conservation

By William Opalka

New York utilities have filed 15 demonstration projects for consideration under the state’s Reforming the Energy Vision initiative, many of them designed to increase consumer awareness and reduce power consumption.

The proposals were due July 1 under a February order by the New York Public Service Commission. The order directed investor-owned utilities to offer joint proposals with third parties to develop New York PSC Bars Utility Ownership of Distributed Energy Resources.)

Iberdrola

Rochester Gas & Electric and New York State Electric and Gas, both units of Iberdrola USA, have proposed three projects: the Energy Marketplace, an ecommerce website enabling consumers and distributed energy resource providers to interact; the Flexible Interconnect Capacity Solution, a model for connecting large-scale, controllable distributed generation to the grid, with the ability of the utility to either dispatch or curtail the power; and the Community Energy Coordination program, which would use community-based energy asset planning to procure distributed energy resources.

National Grid

National Grid has proposed projects at three locations around the state.

Renewable energy integration and automated demand management would be provided at the Buffalo Niagara Medical Campus, along with in-front-of-the-meter solar generation in a lower-income neighborhood. The company also has proposed a partnership with Clarkson University and the State University of New York at Potsdam to determine the feasibility of a community microgrid. In Clifton Park, it is proposing advanced metering for residential and small commercial customers to monitor and control energy use.

Central Hudson Gas & Electric

Central Hudson Gas & Electric, which got a jump on the others when it incorporated its demonstration projects in its recent rate case, has included a targeted demand response program that met PSC criteria. (See Central Hudson Gets Rate Hike, OK on REV Project.)

Its other projects include a utility-scale community solar project that would offer fixed rates to subscribers. Central Hudson and its partners are conducting a feasibility study for a microgrid project. Its “energy exchange” would provide customers with energy management information, including products and services, on a web-based platform.

Orange & Rockland

Orange & Rockland has proposed partnerships with third-party product and service partners to increase customer awareness on energy consumption, motivate customers to participate in utility programs, increase adoption of distributed energy and develop new revenue streams.

Consolidated Edison

Consolidated Edison has filed three separate plans. Its CONnectED Homes program would provide customers with tools to connect them with efficiency programs.

The Building Efficiency Marketplace is intended to illustrate the value of interval meter data analytics in engaging commercial customers to reduce their demand.

The virtual power plant would aggregate 1.8 MW of behind-the-meter distributed solar with battery storage to improve grid resiliency.

July 13, 2015

Massachusetts AG to Study Gas Needs

By William Opalka

Massachusetts Attorney General Maura Healey has commissioned a study to assess New England’s natural gas supplies and other energy needs.

The study, which is being funded by the Boston-based Barr Foundation, will identify options to address electric reliability needs through 2030. Economic consulting firm Analysis Group has been commissioned for the study, which will be completed by October.

“Our goal with this study is to identify the most cost-effective solutions for ratepayers that will also allow us to achieve our regional climate goals,” Healey said in a statement. “As the state makes long-term decisions about additional gas capacity investments, we should understand the facts — what the future demand is, and which cost-effective energy and efficiency resources can be deployed to meet that demand.”

Questions about the need for gas infrastructure have been tackled in studies by various states, stakeholders and ISO-NE, but Healey said they are either flawed or incomplete. “While there have been a number of prior studies conducted, none have answered the precise question of how much additional gas is needed in the New England region and whether that gas can by supplied by [liquefied natural gas] or additional pipeline capacity is needed,” the statement said.

A 2014 study commissioned by ISO-NE concluded the region will face natural gas shortfalls during winters through 2020 due to insufficient pipeline capacity. (See Pipeline Capacity, Retirements Top Concerns in ISO-NE Annual Plan.)

Kinder Morgan has proposed a controversial natural gas pipeline that would bring gas from the Marcellus region of Pennsylvania, through New York and into Massachusetts and New Hampshire, with a terminus at Dracut, Mass. (PF14-22).

The Massachusetts Department of Public Utilities in April opened a docket to evaluate ways to bring extra natural gas into the state, including contracts between electric distribution companies and gas distributors, with cost recovery from ratepayers (15-37).

In light of the study, Healey asked the DPU to reconsider its denial of her motion to stay DPU approval of gas distribution companies’ contracts for capacity on the Kinder Morgan pipeline. The attorney general said there are significant factual disputes to resolve, as well as questions about the legality of pipeline funding through ratepayer charges.

July 13, 2015

PJM PC Briefs

VALLEY FORGE, Pa. — A task force unanimously approved by the PJM Planning Committee last week will craft minimum design standards for greenfield projects that are competitively solicited under Federal Energy Regulatory Commission Order 1000.

PJM and stakeholders said the standards are needed because entities designated for such projects are not required to follow the design standards of the involved transmission owner. (See Task Force Would Create Standards for Order 1000 Projects.)

“The purpose of establishing minimum design standards is to assure a minimum level of robustness is provided such that the new competitively solicited facility would not introduce a weak point in the system in terms of performance,” according to the problem statement.

Participation in the group will be open to all PJM members.

The standards will address transmission lines, substations and system protection and control design coordination. They will take into account factors such as the physical geography of a site and local ordinances.

The rules will not apply to upgrades or non-competitive projects.

The task force also is expected to explore the creation of a “common facility ratings methodology.”

Tariff Tweaks Address Merchant Network Upgrades

The Planning Committee unanimously approved changing some tariff language to more accurately reflect how PJM processes requests for merchant network upgrades.

“We’re not actually changing the way we treat merchant upgrades,” PJM’s Jason Connell said.

He said the language was outdated because it addressed the only type of customer PJM accommodated in 2003: the interconnection customer. In 2006, it added other types of upgrade requests.

The changes address definitions, queue entry, agreements and the capacity market.

Two-Tiered Transmission Project Fee Heads to FERC

PJM will file with FERC a two-tiered fee schedule for proposed transmission projects, the Planning Committee agreed.

For projects of $20 million to $100 million, the RTO will collect $5,000 to cover its study costs. For proposals greater than $100 million, it will charge $30,000.

PJM’s Fran Barrett called the fee schedule, which will be implemented on a two-year trial basis, “conservative.”

“We may be in a situation where we’re under-collecting,” he said, in which case the RTO would lean on the planning system budget. If the opposite turns out to be the case, the excess funds will be disbursed to members.

The Members Committee in February had approved a $30,000 fee for any project greater than $20 million, but planners subsequently concluded that was unnecessarily high. (See PJM Lowers Proposed Tx Project Study Fee.)

Initially, PJM had suggested that $30,000 be assessed on all greenfield projects and on all upgrades costing more than $20 million, but FERC rejected the idea, calling it discriminatory. (See FERC Rejects Fee on Greenfield Transmission Projects.)

Load Model Picked for 2015 IRM Study

The Planning Committee approved using a load model based on the 2003-2012 period in its calculation of Installed Reserve Margin (IRM) requirements.

Last year’s selected load model used the timeframe of 2004-2011, but PJM’s Patricio Rocha said that wasn’t a good fit for this year because load models including 2012 were better aligned with coincident peak distribution. The alternatives were 2001-2012 and 1998-2004.

The 2015 study will set IRM requirements for base capacity auctions for delivery years 2016 through 2019 and establish the initial IRM for 2019/20.

— Suzanne Herel