Electricity Markets

Panelists argue that Calif., PJM grid projects fall short of FERC rule

It has been more than 15 years since the Federal Energy Regulatory Commission issued its Order No. 890 to increase transparency in transmission system planning, but panelists at a recent conference outlined how approaches to local transmission planning in the California ISO and PJM Interconnection show the disconnect between the final rule’s vision and today’s reality.

A panel at the Energy Bar Association’s 2019 annual meeting and conference in Washington, D.C., on May 7 examined electric transmission investments and Order 890, a final rule adopted by FERC in 2007.

Panelists focused on local transmission planning. In the PJM Interconnection, local transmission projects are referred to as supplemental transmission projects, while in the California Independent System Operator they are often referred to as asset management projects or capital maintenance projects, noted panel moderator Aspassia Staevska, Assistant Counsel, Law Bureau Pennsylvania Public Utility Commission.

Lisa McAlister, Senior Vice President and General Counsel, American Municipal Power (AMP), presented a slide during the session that broke down the types of PJM transmission projects and trends for those projects.

The slide showed three different types of transmission projects in PJM: (1) baseline projects needed for reliability; (2) supplemental projects, which are planned and driven by transmission owners and not needed for reliability; and (3) projects that fall under the baseline category but are designed and driven by transmission owner criteria.

What the slide shows, McAlister noted, is that in 2018 “PJM only designed and planned seven percent of the transmission projects that were proposed in PJM.”

From AMP’s point of view, the supplemental projects “don’t get the same regulatory oversight and process” as the baseline projects do, “but we’re footing the bill for all of them. The real important thing to us is the process is using the right considerations and that we’re receiving comparable service.”

She noted that AMP “is not unwilling to bear our costs of reasonable and prudent transmission expansion and we are not anti-transmission infrastructure.”

Order 890

Much of the discussion during the panel centered around Order 890, under which the Commission reformed its open-access transmission regulatory framework.

At the time, FERC said the final rule was designed to, among other things, strengthen the pro forma open-access transmission tariff, or OATT, to ensure that it achieves its original purpose of remedying undue discrimination and increasing transparency in the rules applicable to planning and use of the transmission system.

McAlister noted that Order 890 included nine principles applicable to transmission planning, several of which she said are particularly important to AMP.

McAlister said that with respect to Order 890’s coordination principle, there is a requirement that transmission owners and RTOs allow meaningful input and participation from customers in the development of transmission plans.

“The openness principle is also very important to us,” the AMP official said. “It means that the planning meetings have to be open to all affected parties,” McAlister said, noting that the Commission emphasized that the overall transmission planning process has to remain open.

She said that transparency is the most critically important principle for AMP that came out of Order 890 “and what that said was that the transmission providers have to reduce to writing and make available the methodology, criteria and processes” used to develop transmission plans.

FERC voiced concern about PJM transmission planning process

In an August 2016 show cause order, FERC voiced concern that the transmission planning process governed by PJM’s operating agreement was not providing stakeholders with the opportunity for early and meaningful input and participation in the transmission planning process, as required by Order 890.

The Commission said that it appeared that PJM transmission owners were conducting significant local transmission planning activities before identifying a need for a project in a public forum, McAlister noted.

In response, PJM transmission owners said they were going to create a new section of the PJM tariff referred to as Attachment M3.

But M3 “is just a high-level process document,” McAlister said, adding that it “is not really a description of how the planning process works. It doesn’t have any specific criteria or evaluation methodology, but if you look at the operating agreement and compare it to the baseline planning requirements, there is significantly more detail in the operating agreement.”

PJM has hundreds of pages of documents in its manuals “that even more clearly spell out exactly what the planning process is going to look like, so the stakeholders are on the same page and know what to expect. There’s nothing equivalent for supplemental projects.”

The PJM TOs have held one meeting so far to provide an update on progress related to M3 implementation. “They presented a package at that meeting that indicated they were fully complying with M3 and we disagree,” the AMP official said. “It was pointed out that M3 requires the transmission owners to provide their models” at a meeting that involves the first phase of the planning process “and they are not doing that.”

California transmission rates have increased

Another panelist, Katie Mapes, a partner with the law firm of Spiegel & McDiarmid, LLP, said that transmission rates in California have increased drastically over the last decade or so. “I think the statistic that’s usually bandied around is that they’ve doubled since 2008 and I think current projections show they’re likely to double again in the next ten years.”

Mapes said that for a long time, “it wasn’t exactly clear why this was happening. The fact of the matter is load isn’t growing in California for the most part, with the exception of some Silicon Valley communities. There aren’t large numbers of transmission miles being added in California at this point in time.”

Also, the CAISO’s projections were not showing transmission rates going up as much as they have been, “so everybody was a little baffled,” she said.

What became clear, Mapes said, is that the bulk of the transmission rate increase “is in projects that we’re not being reviewed through the California ISO’s transmission planning process and are instead in this category of projects called asset management projects.”

An example would be an upgraded substation, “but we’re not talking about building new miles of transmission line,” she said.

Mapes explained that in 2016 and 2017, investor-owned Pacific Gas & Electric spent around $750 million a year each year on these types of projects, which is about 60 percent of its total capital transmission spending. Southern California Edison and San Diego Gas & Electric, also investor-owned utilities in the state, spent less, Mapes said – about $188 million in 2016 for SCE and about $50 million that year for SDG&E.

“One thing that ratepayers and customers started to realize was that we were paying this bill and we saw the rates increasing every year, but we weren’t seeing a lot of transparency in how that was happening,” Mapes told the audience of energy attorneys and industry professionals.

Parties file complaint at FERC

In early 2017, the California Public Utilities Commission, Northern California Power Agency, the City and County of San Francisco, State Water Contractors and the Transmission Agency of Northern California filed a complaint at the Federal Energy Regulatory Commission against PG&E.

The parties to the complaint said that PG&E was violating Order 890 by performing transmission work without putting it through any kind of open and comprehensive transmission planning process, Mapes noted.

The complaint relied heavily on the work done in PJM by AMP and others and the Commission’s order to show cause in that docket, she went on to say. “The arguments that the complainants made was that the asset management projects that PG&E was doing were very similar to the supplemental projects in PJM,” Mapes said.

The parties to the complaint (Docket No. EL17-45) said that PG&E was conducting more than 80% of its transmission planning — equal to 60% of its annual capital investment — on an entirely internal basis, without providing any opportunity for stakeholder input or review.  “As a result, PG&E is in violation of its obligation under Order No. 890 to conduct an open, coordinated, and transparent transmission planning process,” the complaint said. FERC in August 2018 denied the complaint.

Meanwhile, SCE in late 2017 filed an attachment to its tariff at FERC – a transmission maintenance and compliance review (TMCR) process – that called for a review of asset management projects every year.

The utility committed to providing a report to stakeholders, taking input from stakeholders in written form, holding a stakeholder meeting and then completing a final report.

In response to the SCE proposal, FERC held a technical conference in May 2018 to address local transmission planning within the CAISO, as well as the SCE and PG&E complaint dockets. Mapes noted that SCE’s TMCR process is in effect, with its first cycle set to soon kick off.

Exelon official sees differences between PJM, CAISO project

Gary Guy, Assistant General Counsel at investor-owned Exelon Corporation, said that “the supplemental project concept starts with the premise that everything’s supplemental, everything’s done by the transmission owner, unless you’ve signed an agreement with the RTO to cede authority to the RTO, so the definition is in the tariff.”

Supplemental project “means a transmission expansion or enhancement. That means it’s under the RTEP,” which refers to PJM’s regional transmission expansion plan. “We’re not talking about the pre-existing infrastructure,” he said. “PJM does not plan anything with respect to replacement of existing transmission assets.”

Guy said that when it comes to the CAISO and PJM proceedings, “FERC was not schizophrenic. FERC reads what people put in front of them.”

He said that FERC “didn’t tell California one thing that contradicted what they told PJM. They told PJM, you’re telling us that you want us to write an order dealing with expansion and enhancement. Alright, we’re telling you you’re under 890. California, you’re telling me you want me to write an order dealing with something that’s not expansion or enhancement, alright I’ll tell you you’re not under Order 890.”

Brattle report examines state of competition in transmission space

Another panelist, The Brattle Group’s Judy Chang, provided an overview of a recently released Brattle report on transmission. The report examined the experience with competitive development processes for U.S. transmission projects under FERC Order No. 1000. In Order 1000, which was issued in 2011, FERC reformed its transmission planning and cost allocation requirements.

Chang’s presentation also included a slide illustrating that of the $75 billion in transmission investments by FERC-jurisdictional transmission owners in ISO/RTO regions between 2013 to 2017, approximately 47 percent was made without comprehensive ISO/RTO and stakeholder engagement through the regional planning process.

She also discussed the state of competition in the transmission space. This aspect of the analysis was funded by LS Power, a transmission and generation developer.

The analysis found that across the U.S., only about 3 percent of spending on FERC-jurisdictional transmission investments between 2013 through 2017 was subject to competition.

Chang also said in her presentation that experience with more than a dozen transmission projects selected through the ISO/RTO competitive planning processes reveal potentially large cost advantages of competition.

On average, winning bids of 15 competitive transmission projects have been priced 40% below the ISO/RTOs’ or incumbent transmission owner’s initial project cost estimates, the Brattle analysis found.

In addition, the analysis found that the experience in the U.S. indicates a significant potential for customer savings. 

Specifically, if competitive projects can be developed as bid (without further cost escalations), savings would be 28%-50% relative to the costs had these projects been traditionally developed, a slide from Chang’s presentation states.

If costs of competitive projects escalate like traditionally-developed projects, the savings would still be between 15%-30%, the analysis determined.

Resolution on grid costs adopted at Association’s Legislative Rally

The American Public Power Association’s members in February approved several new policy resolutions including one that highlighted the Association’s concerns about rising transmission costs.