Exelon executives expressed confidence during a fourth-quarter earnings call that programs supporting the company’s nuclear generation fleet will expand into other states this year.
“Since our last earnings call, we continue to see positive momentum for policy changes … at state, FERC and RTO levels,” said Joe Dominguez, vice president of governmental and regulatory affairs and public policy.
Dominguez said Exelon is focused on three goals: ensuring that resilient resources are compensated fairly; addressing the price formation flaws that PJM has identified; and preserving and expanding zero-emission credit (ZEC) programs and similar initiatives. All three would benefit the company, which has the largest nuclear fleet of any U.S. generator and has seen its plants undercut in power markets by cheaper natural gas and renewable energy.
According to its critics, Exelon is seeking subsidies for plants that are no longer economical to operate. But the company maintains that it is asking to be compensated for the reliability of nuclear generation, which can run constantly and don’t emit greenhouse gases.
CEO Christopher Crane said the company will continue to defend the ZEC programs in Illinois and New York and work to get similar programs enacted in New Jersey and Pennsylvania. The New Jersey Legislature is considering a bill that would subsidize the state’s nuclear plants.
Exelon also is urging FERC to adopt PJM’s price formation proposal, Crane said. PJM stakeholders endorsed the RTO’s problem statement and issue charge to examine price formation procedures for its energy markets at a Markets and Reliability Committee meeting in December.
Exelon’s Three Mile Island nuclear power plant is in Pennsylvania, where the company is working to get subsidies for nuclear generation.
The PJM-backed revisions would allow large, inflexible generators like coal-fired and nuclear to plants to set LMPs, which current rules prohibit. When such units are dispatched despite LMPs below their offers, they must seek reimbursement through uplift payments. (See PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)
Exelon earned $1.87 billion ($1.94/share) in the fourth quarter of 2017, compared to $204 million ($0.22/share) a year earlier. Its adjusted earnings per share were 55 cents, which fell short of the Zacks Investment Research consensus estimate of 62 cents.
Exelon’s revenue in the quarter was $8.38 billion, up from $7.86 billion a year prior and ahead of the Zacks consensus estimate of $7.6 billion.
NEW ORLEANS — The company about to begin construction on a $15.2 billion LNG export terminal is not concerned about fears of oversupply, an official told the Gulf Coast Power Association’s MISO South regional conference Thursday.
“It is true that at this point — with new supply coming on in different parts of the world, including the U.S. — there is a momentary glut of LNG,” acknowledged Jason French, vice president of government and public affairs for Tellurian. “However, virtually everyone who looks at it [agrees] there is going to be a … shortage of LNG by the middle of the next decade,” he said, noting that the number of countries importing LNG has grown to 47 from 29 in the last three years.
French formerly worked for Cheniere, whose LNG export terminal was based on 20-year take-or-pay contracts and $120/barrel oil prices.
“We’re starting to see smaller, modular designs. We’re not in a $120 oil environment so we have to be more competitive,” French said. Tellurian and other exporters are offering portfolios of short-term, mid-term and long-term contracts, he said, as well as taking on equity partners in the projects, unlike the typical 70% debt structure in the first export terminals.
“Sometimes you’ll hear negativity about our industry because of this momentary glut in supply. I tell you, people are steering you wrong when they tell you that, because the future is very bright for what we’re doing.”
Tellurian’s Driftwood terminal, on the Calcasieu River, south of Lake Charles, La., is expected to spend $400 million to $500 million in annual operations and maintenance expenses. Tellurian is currently in discussions with electric providers for Driftwood’s 167-MW load.
Driftwood LNG Project Map | Tellurian Inc.
Despite his confidence, French displayed some humility about his predictions, noting that much of Tellurian’s management came from Cheniere, which opened its Sabine Pass LNG import terminal — the nation’s first import facility — just before the domestic shale gas boom eliminated the need for imports. “We got this wrong once,” he said.
David Dismukes, executive director of Louisiana State University’s Center for Energy Studies, said capital expenditures in Louisiana and Texas resulting from cheap gas will total $318 billion between 2011 and 2025.
Dismukes said economic theory suggests that U.S. gas prices will rise to the global “proxy” as LNG exports increase, undermining industrial customers who have built new facilities in Louisiana to capitalize on cheap gas as a feedstock. Thus far, however, he said it has been the inverse, with global prices coming down to Henry Hub prices. “That’s not to say it’s going to be like that in permanency, but at least in the near term, we’ve seen this test out,” he said.
MISO says it will await a FERC decision after a D.C. Circuit Court of Appeals panel vacated a series of commission orders that allowed new generators in the RTO to self-fund network transmission upgrades.
In a 2-1 vote Jan. 26, Judges David Tatel and Laurence Silberman said the commission had failed to consider the arguments of Ameren and five other transmission owners who complained the policy forced them to accept “risk-bearing additions to their network with zero return.” The TOs argued that they essentially act as “nonprofit managers” of network “appendages,” and that under the Federal Power Act and the Constitution, FERC cannot force them to construct and operate generator-funded network upgrades.
The case was handed back to FERC on remand; the court said FERC had not yet provided a suitable answer to the TOs’ complaint (16-1075).
Judge Judith W. Rogers filed a lengthy dissent supporting FERC and rejecting the petitioners’ argument that the commission’s orders require them to operate partly as a nonprofit business. “Not every regulatory decision requiring action by a regulated entity gives rise to a corresponding entitlement to a return,” Rogers wrote.
MISO spokesman Mark Brown said the RTO will continue to monitor the case, but it has no plans to act on the ruling until FERC issues an order.
“In the meantime, we are evaluating the implications for MISO and will be prepared to move forward upon final outcome,” Brown told RTO Insider.
But Ameren seeks a different, more immediate, outcome.
“Ameren looks forward to MISO filing revised tariff sheets to reinstitute the tariff provisions that were in effect immediately prior to the effective date of the vacated provisions, as expeditiously as practicable,” the company said in an email.
Under MISO’s Tariff, generation owners are responsible for funding 100% of network upgrades for projects below 345 kV and 90% for projects 345 kV and above, with the remaining 10% folded into the TO’s rate base.
The Tariff allows two methods for generation owners to fund the construction of network upgrades: either the TO fronts the capital, recovering costs over time through a charge on the interconnecting generator; or an interconnecting generator provides the capital. Under the generator funding option, the TO does not earn a return on financing network upgrades; the Tariff leaves it to the interconnecting generator to choose between the two funding options.
Originally, MISO allocated the costs equally between the generator and TO, but FERC determined that local transmission customers shouldered a disproportionate share of the cost of upgrades that stood to benefit more remote customers. FERC then issued a series of orders from 2015 to 2016 authorizing new generators to self-fund construction for network upgrades, regardless of whether grid owners wanted to finance it. The commission ruled that allowing TOs to choose a funding option — coupled with the power to levy subsequent charges to generators — might allow them to discriminate among generators.
The court, however, said the commission’s reasoning was “weak” and there was “neither evidence nor economic logic supporting FERC’s discriminatory theory as applied to transmission owners without affiliated generation assets.” It doesn’t make sense, the court said, that “FERC may compel transmission owners to operate the upgrades without an opportunity to earn a return.” The court noted that of the six petitioning MISO TOs, only one — Ameren — owns generation.
The court also found that not all network upgrade costs and risks are “baked in” when generators pay for them, and TOs must “bear liability for insurance deductibles and all sorts of litigation, including environmental and reliability claims.”
Rogers said her colleagues ignored the history behind FERC’s open access rules. “The court could hardly dispute that Ameren has ‘a competitive motive’ to favor affiliated generators over other generators. The commission addressed this circumstance in Order No. 888, and the Supreme Court thereafter observed that ‘utilities’ control of transmission facilities gives them the power either to refuse to deliver energy produced by competitors or to deliver competitors’ power on terms and conditions less favorable than those they apply to their own transmissions.’”
Relief
FERC told the court that its review was premature because the TOs could seek increased rates by filing Section 205 petitions. But the majority said that option would not provide the relief the TOs sought.
“First, FERC’s precedents do not provide compensation for several of the classes of risks that petitioners allege will accompany construction and operation of the network upgrade facilities. For example, fines and penalties for violations of mandatory reliability standards and environmental regulations are generally charged directly to the utility, not passed through to customers via rate increases. Further, FERC has stated that it takes a comprehensive view of a company, its employees and its operations when wielding its enforcement power against the utilities it governs. As such, compensation for the types of risks identified by the petitioning transmission owners may not be possible, even if proven in a future hearing.”
The court said it had no need to decide whether FERC is barred by the Federal Power Act or the Constitution from forcing TOs to construct and operate generator-funded network upgrades.
“Indeed, we should not do so until the commission has developed a record by considering that question itself,” the court said. “But we are troubled by the prospect of allowing the orders to continue in the interim.
“FERC may determine on remand that a transmission owner’s consent is required to impose generator-funded network upgrades, or that it would be unjust or unreasonable to force the transmission owners to accept increased risk with no increased return,” the court continued. “If it does not, Article III courts may subsequently require it to do so.”
NEW ORLEANS — Regulators from Arkansas, Mississippi and Louisiana competed last week to heap scorn on Energy Secretary Rick Perry’s bid to boost coal and nuclear plants while praising FERC’s rejection of the Notice of Proposed Rulemaking.
The remarks came during a panel discussion with FERC Commissioner Robert Powelson at the Gulf Coast Power Association’s MISO South regional conference Feb. 8.
“When the administration chooses to protect coal — and omits the major fact that gas produced by fracking competes with coal — it’s political malpractice that puts my ratepayers at risk,” said Republican Ted Thomas, chair of the Arkansas Public Service Commission and the Organization of MISO States. “And it hacks me off.”
“A lot of time we [on the Louisiana Public Service Commission] don’t all agree,” said Commissioner Mike Francis, a Republican. “This particular issue gave us quite a bit of heartburn, and we unanimously objected.”
Louisiana regulators and the Mississippi Public Service Commission filed joint comments with FERC in October saying Perry’s proposal was based on unsupported conclusions, would harm ratepayers, undermine competition and intrude on state jurisdiction.
“This is hypocrisy run amuck,” said Mississippi PSC Chairman Brandon Presley, the lone Democrat on the panel. “How long have we been hearing about ‘Let’s make these decisions on the local level, get big government out of our lives.’ … And all of the sudden, in 15 days we’re supposed to upend the markets.
“I represent the poorest counties in the poorest state in the United States of America, and they don’t need this type of deal,” he continued. “They don’t understand why they should prop up an industry.”
Powelson said the stakes for FERC were clear when the commission voted unanimously to reject the NOPR and create a new docket to examine grid resiliency. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
“We either stand for … organized markets and the rule of law, or we don’t,” Powelson said. “We stood our ground, demonstrated to everyone in this room that regulatory certainty is alive and well at 888,” a reference to the address of FERC headquarters.
Powelson criticized some fuel partisans for “creating a lot of hysteria” in questioning the reliability of natural gas generation.
“I had to correct someone in my office [who said] that gas is not a baseload resource,” he said. “Now if you say that in Louisiana or Texas or Pennsylvania, they’re fighting words.”
‘Black Swan’ Events
Thomas said planning for high-impact, low-frequency “black swan” events is “one of the most difficult things to rationally deal with.”
“There should be regional differences with respect to this because different regions have different threats. Minnesota doesn’t need to pay a bunch of money for [protection from] hurricanes. California doesn’t need to pay a bunch money for [protection from] tornadoes,” Thomas said. “If you’re in the ice cream business, you have a different view than [if] you’re in another business. And to me this is the one place where microgrids actually make some sense — that if people need extra reliability then they can come up with a way to pay for it without changing the standard for everybody. So, your hospitals and folks that need it — there ought to be ways for them to bear that cost rather than spreading it around.”
Bear: No Resilience Problem in MISO
Speaking earlier, MISO CEO John Bear said the RTO is still developing its response to FERC, but it doesn’t expect major changes because state regulators and RTO members have ensured resilience through integrated resource planning.
“We don’t have a resilience problem. … We’re in a really good position right now as a region because of the hard work those folks have done. So I don’t think they need to come in and put anything in that’s significantly different from what we have today.”
However, Bear said MISO and its neighbors should improve their seams coordination to help the grid when it is “under stress” from severe weather.
“How those seams operate, the seams agreements and the way we use transmission, the way we dispatch between us … I think that’s the area where we really need to focus so that we’re all working together when those situations occur, as opposed to everybody’s looking inside their own tent and maybe working against each other.”
Tipping Point for Renewables?
In response to a question, Powelson said FERC may have to consider whether state renewable portfolio standards, subsidies for nuclear plants and incentives for offshore wind could reach a “tipping point” and begin to undermine wholesale markets.
“If you would have told me that a combined cycle gas plant with a 6,600 heat rate is facing problems in a market like California with renewables ramping up and that gas resource being dispatched [down] and not being able to handle marginal costs in that market, I would never have imagined that scenario,” Powelson said. “So it is something that is on our radar screen. … Over the next five years I think there will be some friction points going forward for us.”
Powelson also said the commission should reconsider whether capacity market incentives are properly designed. “Is a three-year [forward] capacity auction like PJM — does that really incent an investment, or should we be looking out five years in that construct?” he asked. “That’s a debate that I’ve teed up within the [FERC] building.”
NEW ORLEANS — Competitive transmission, hurricane forecasts and maximum generation alerts were among the topics at the Gulf Coast Power Association’s MISO South regional conference Feb. 8. Here’s some of what we heard.
MISO CEO John Bear predicted the Hartburg-Sabine Junction market efficiency project will produce better than a 1.35:1 benefit-cost ratio, although he acknowledged it did not have “broad” stakeholder agreement.
“I do think it’s the right answer. I think it really does help us with our reliability issues in the South, with load pockets; making sure that we can support the growth that we need from an economic standpoint, from a reliability standpoint, from a resiliency standpoint. It checks all those boxes.”
The RTO issued a solicitation for competitive bids on the estimated $130 million, 500-kV project in eastern Texas last week. (See Hartburg-Sabine Tx Project Open for Bids.)
GCPA Executive Director Tom Foreman asked Bear why there hasn’t been more transmission built through MISO to deliver SPP’s growing wind generation to the east.
“The economics have to be right for both parties,” Bear responded. “There’s a lot of analysis underway to look at that, but we’ve got a lot of work to do to make sure it makes the most sense. With the amount of wind that’s on the system today and low gas prices, more wind doesn’t necessarily lower LMPs.
“Trying to understand how to operate [the SPP] seam reliably and efficiently is also really important,” Bear added. “We don’t have as mature a relationship working with SPP on that seam because it hasn’t been [there] as many years” as MISO’s seam with PJM.
Moving Beyond the ‘Cone of Uncertainty’
Chris Hebert, TropicsWatch manager for StormGeo, said the “cone of uncertainty” developed about 15 years ago to forecast hurricanes’ paths is no longer the state of the art.
Hebert explained that the cone is actually constructed by joining the edges of a series of circles, each representing a 67% probability of the storm passing through. As forecasting has improved, the cones have gotten narrower.
But that can lead to dangerous complacency, he said, noting that Hurricanes Katrina (2005), Ike (2008), Joaquin (2015), Matthew (2016) and Harvey (2017) strayed outside their predicted paths. “Being outside the cone doesn’t mean you’re safe,” he said.
Hebert said a consensus of models is better at indicating the current uncertainty and potential impact of storms.
Judith Curry, president of the Climate Forecast Applications Network, said she used “ensembles” of models and Monte Carlo sampling to help Florida Power & Light pre-position utility crews before Hurricanes Hermine (2016), Matthew and Irma (2017).
Curry said it’s too early to blame climate change for affecting either storm intensity or frequency. “It’s impossible to separate what might be global warming from natural variability,” she said, adding that data on warming’s impact on storms are unlikely to be clear until about 2050.
The consensus is that warming will cause an increase in storm intensity — including more Category 4 and 5 hurricanes — but that the overall number of tropical cyclones will decrease, Curry said. “If those predictions are true, we may have smaller overall impacts from hurricanes later in the century. But this is all very speculative. The climate models are nowhere near good enough to actually predict this,” she said.
Sallie Rainer, CEO of Entergy Texas, discussed her utility’s response to Hurricane Harvey, which dropped 50 inches of rain in its service territory over eight days in late August and early September, flooding six major substations.
The experience is leading the company to seek more information about local watersheds, she said. “Understanding where those bayous and tributaries will dump the water when we’ve had 50 inches come in … and being able to lay that over our topology and our equipment [will show] what we need to protect … if we need to raise control houses, put floodwalls up.”
Phillip May, president of Entergy Louisiana, said the reduction in the federal corporate income tax from 35% to 21% will result in about $100 million in annual savings for the company’s customers. “We believe tax reform will have significant and meaningful benefits to our customers,” he said.
Max Gen Events
During a discussion on MISO’s maximum generation events in April 2017 and January 2018, Independent Market Monitor David Patton reiterated his call for the RTO to exercise more control over the scheduling of maintenance outages.
Patton said an excessive number of planned outages contributed to 22 days of conservative operations in load pockets in spring 2017, including three days of maximum generation alerts in April 2017, which included an April 4 emergency max gen event following the loss of a large nuclear unit in the South during a period of high load.
“It would have been great if we’d started our outages earlier or spread them out, because we had more capacity than we knew what to do with in the peak period and then we scheduled ourselves into an emergency in terms of the outages in March and April,” he said. Under its Business Practices Manual, MISO can only “recommend [an outage] schedule that maintains system security and minimizes adverse impacts.” (See MISO South Outages Worry RTO, Monitor.)
Patton said the biggest problems occur when transmission and generation outages are scheduled simultaneously in the same area. “If you take a major line out of service and then you take a large generator that played a key role in relieving the flows into that area, you can end up with congestion that’s very difficult to manage and generates a lot of cost quickly.”
Patton, however, said the South would have been in worse shape had it not been part of MISO. “Having MISO operating the integrated region between the South and Midwest increases reliability in both regions,” he said.
He recommended that MISO purchase capacity in four seasonal tranches to ensure sufficient generation year-round and give resources options on when to accept capacity obligations. Load-modifying resources — demand resources and behind-the-meter generation that provide capacity — shouldn’t be summer-only, he said.
Richard Doying, executive vice president of operations, said MISO staff are preparing a white paper on whether it should be planning seasonally rather than its traditional focus on the summer peak. He noted that LMRs represent almost 10% of the RTO’s fleet.
SPP’s Market Monitoring Unit (MMU) last week conducted its first quarterly market report webinar, importing a practice MMU Executive Director Keith Collins used while at CAISO.
“It is not only a great forum for us to present on our quarterly report, but it also allows for great interactive discussion between market participants and market monitoring staff,” said Collins, who joined the MMU last year.
Staff reviewed the report’s highlights, focusing, as the report did, on the SPP market’s growing frequency of negative price intervals. The MMU said the market’s practice of self-committing resources in the day-ahead market may be exacerbating the situation.
“We’re not saying negative prices are bad, but they are an indication of what happens on the system as a consequence of thousands of megawatts not participating in the day-ahead market,” Collins told participants. “When they show up in the real-time market, it can create this disconnect.”
Negative Prices | SPP MMU Fall 2017 Quarterly Report
Collins said the MMU will repeat the practice following each quarterly and annual market report. The calls are open to members, market participants and regulatory staff, among other stakeholders.
“Our goal is to improve the markets through education and understanding of market outcomes,” he said.
December MISO-SPP M2M Results in $4.2M in Charges
SPP recorded its third consecutive month of multimillion-dollar market-to-market (M2M) payments from MISO in December, staff told the Seams Steering Committee on Feb. 7. The month’s $4.2 million in charges pushed the amount of M2M payments to SPP past $36.8 million.
M2M Update December 2017 | SPP
Permanent and temporary flowgates were binding for 531 hours in December. SPP’s Riverton-Neosho-Blackberry flowgate on the Kansas-Missouri border was once again responsible for the bulk of the charges.
The two RTOs began the process in March 2015. SPP last month said it has reimbursed MISO more than $2.25 million after resettlements of several M2M flowgates, and that it will continue to perform “limited” resettlements because of a memorandum of understanding between the two. (See “SPP Pays MISO $2.25M After M2M Resettlements,” SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2018.)
Staff also briefed the committee on the Feb. 27 MISO-SPP Interregional Planning Stakeholder Advisory Committee meeting. The RTOs’ staff and stakeholders will discuss improvements to the Coordinated System Plan, which has identified four potential seams projects in two previous iterations. None of the four survived regional reviews.
SPP is also trying to meet with Associated Electric Cooperative Inc. before March 9. Staff have drafted a scope that identified needs from its 2018 Integrated Transmission Planning Near-term Assessment that are “electrically significant to the SPP-AECI seam.”
Board Approves Non-Jurisdictional Tariff Change
The Board of Directors approved a Tariff revision that incorporates a refund obligation for SPP’s nonpublic transmission-owning utility members during a special conference call Monday afternoon.
The measure addresses a FERC directive that SPP require non-jurisdictional transmission owners to refund revenues received associated with their service, and that it enforce the membership agreement in court (EL18-19). The RTO has a Feb. 28 filing deadline in the docket. (See FERC Backs off Nonpublic Utility Refunds in MISO, SPP.)
The 20-person Members Committee was divided on its advisory vote to the board, with five members — Empire District Electric, Oklahoma Gas & Electric, Public Service Company of Oklahoma, Southwestern Public Service and Westar Energy — casting opposing votes.
The proposal, which was recommended by the Corporate Governance Committee, includes a provision that should there be a conflict between a FERC refund order and state statute, the refund amount would be deemed uncollectable. Members questioned why non-jurisdictional members should be treated differently than investor-owned utilities and whether their customers might pick up the tab for those entities unable to provide refunds.
“If our customers are overpaid and there’s a refund order, our customers are left with a short amount,” said OG&E’s Greg McAuley.
Kansas City Power & Light’s Denise Buffington, who represents IOUs on the CGC, said she supported the measure because of her understanding that the Nebraska Constitution prevents its entities from delegating authority to someone else.
“I’m OK with this if SPP can show how everyone else will be kept harmless,” she said. “I will be closely scrutinizing the SPP filing. If it doesn’t show harm to other members, we will be filing comments in the docket.”
FERC ruled Friday that the developer of a proposed 1,500-MW Indiana wind farm must go to the end of the interconnection queue to move its point of interconnection (POI) 2.9 miles.
The commission’s Feb. 9 order rejected Harvest Wind’s request for a waiver allowing it to change the POI without triggering the “material modification” language under PJM’s Tariff. FERC sided with PJM in requiring a new queue application and facilities study (ER18-615).
Colorado-based Renewable Energy Systems Americas acquired the Harvest Wind project after the previous developer agreed in late 2016 to move to a second POI after AEP Indiana Michigan Transmission said the original was not a suitable spot for the wind farm’s 765-kV switchyard.
RES Americas said it learned in fall 2017 that the new location, POI 2, had some of the same problems as the original location, including wetlands and endangered species concerns. In addition, noise from the switchyard’s transformers would be too loud because of nearby houses, the company said in its Jan. 5 waiver request.
The developer said its proposed interconnection, POI 3, is “electrically identical” to the current location because it is just 2.9 miles away on the same 765-kV transmission line.
PJM opposed the request, arguing that the waiver would delay other projects in the queue because of the size of the wind project and the need for transmission restudies.
The commission agreed with PJM, finding that “Harvest Wind has not sufficiently demonstrated that it acted in good faith. Harvest Wind states that it became aware in September 2016 that both POI 1 and POI 2 presented some complicating factors due to site topology, but at that time it did not believe these factors were insurmountable. … Moreover, Harvest Wind fails to explain why it did not discover these additional complications for almost a year after initially being put on notice that complications existed at POI 1 and POI 2, demonstrating a lack of due diligence on Harvest Wind’s part.
“Harvest Wind has not sufficiently demonstrated that granting the waiver request will not have undesirable consequences or harm third parties,” the commission continued. “We agree with PJM that changing the point of interconnection at this late stage would introduce uncertainty that could well impact other lower-queued interconnection customers and that such restudy of the point of interconnection would require reassessment of protection, requiring the expenditure of time and resources, thus burdening and harming other parties.”
RES Americas said in its waiver request that it might be forced to abandon the project if the waiver were not approved.
An RES Americas spokesman said the company was “planning to proceed with the project” but did not say why a delay might force it to abandon it.
FERC approved PJM Tariff and Operating Agreement revisions incorporating two pro forma pseudo-tie agreements and a pro forma reimbursement agreement effective Nov. 9, 2017.
The commission’s Feb. 5 order rejected protests by MISO’s Independent Market Monitor, NYISO, American Municipal Power, Illinois Municipal Electric Agency and North Carolina Electric Membership Corp. (ER17-2291). (See Critics Protest PJM Dynamic Transfers Plan.)
| MISO, PJM
In its protest, NYISO said PJM’s rules will likely cause “adverse reliability impacts” and “exacerbate interregional seams.” But PJM pointed out that there are no resources currently pseudo-tied into PJM from NYISO.
The MISO Monitor David Patton contended FERC should not consider PJM’s proposal separately from other pending pseudo-tie proceedings. The plan creates “substantial economic and reliability harm to the customers in [the MISO and PJM] area,” he said.
The commission was unpersuaded, saying: “The terms of the proposed revisions and pseudo-tie agreements are not unjust and unreasonable merely because the commission has not yet acted in the other proceedings.” FERC also rejected the Monitor’s request for a technical conference.
“We agree with PJM that the pseudo-tie agreements and corresponding Tariff and Operating Agreement revisions promote uniformity among the pseudo-tie and dynamic schedule requirements and increase the transparency and efficiency of the implementation process,” the commission said.
California regulators on Thursday approved an order putting new requirements on community choice aggregators (CCAs), saying the decision did not come easily.
At the same time, CCAs and their supporters are arguing for more transparency and control over resource adequacy (RA) procurement.
“I just have overwhelming anxiety about the purpose of resource adequacy,” California Public Utilities Commission President Michael Picker said, addressing a crowded hearing room at commission headquarters in San Francisco after a public comment period. “It seems as if people have forgotten the energy crisis of 2001 and 2002.”
The State Legislature authorized the creation of CCAs in 2002 in response to the energy crisis, allowing local governments to directly contract for energy services to serve their residents. CCAs did not begin appearing until 2010 but have since grown rapidly.
Until now, CCAs have avoided the requirement to carry RA reserves, even as they’ve taken on a greater share of California load. Instead, customers of investor-owned utilities have been left with stranded costs because of the timing of load forecast submissions and RA allocations, in some cases procuring RA for customers about to be served by CCAs. Cost-shifting can run into the tens of millions of dollars annually, the CPUC said.
Picker struck an assertive tone on the RA issue, saying that grid reliability is at stake as procurement of electricity disaggregates through CCAs, which he’s unsure could meet critical grid needs.
“It really makes me nervous and it makes me wonder if people are really prepared to embrace this opportunity to serve as [load-serving entities],” Picker said, adding that the CPUC made reasonable efforts to accommodate the concerns of CCA supporters.
The CPUC made changes to its initial RA proposal in response to written comments, including extending the deadline for CCAs to submit their RA implementation plans until March 1 in order to allow several of them to begin serving their new customers in 2019. The CPUC also created two waiver options, one in which CCAs and IOUs can agree on the CCA’s RA requirements and cost responsibility, and another stipulating that if agreement was not reached, the CCA agrees to be bound by a future CPUC determination in the RA proceeding regarding its RA cost responsibility.
Many of the more than 40 registered speakers attending the CPUC hearing were there to speak against the CCA ruling. West Hollywood City Councilmember Lindsey Horvath told the CPUC that CCA customer energy costs must be determined in a fair and open process.
“How can we properly determine our fair share without access to contracts we’re being asked to account for?” Horvath asked. “We are glad to see the direction the commission is moving with in the current form of its resolution, but we’re not there yet.”
The CPUC introduced the proposal in December with a comment period near the holidays, leaving CCA representatives saying the expedited order did not give them time to provide input. (See California Proposes Resource Adequacy Obligations for CCAs.) Other proponents said it would delay CCA creation and slow achievement of climate goals. CCAs have grown rapidly and are popular as a way for localities to take control of energy consumption, with many marketed as green energy options.
But Picker said that if the decision delays the implementation of CCAs, “we are just going to have to live with that.” The consequences of having grid failure “can wipe the slate clean,” he said, again invoking the reliability crisis of the early 2000s.
Commissioners appeared sympathetic to CCA supporters, but Martha Guzman Aceves said that issues with the RA program have led to more procurement of natural gas generation.
“This is a problem to reaching our climate goals,” she said. “This is actually an environmental justice issue for me.” She added that, “Sometimes we don’t use the best process, I totally acknowledge that. But we need to deal with this problem now.”
“There has got to be good dialogue, there has to be trust,” Commissioner Carla Peterman said. “The last thing I want is to exacerbate tension between the CCAs, the utilities and the commission.”
In its order, the CPUC said: “Numerous commenters assert that the resolution violates their due process rights. We disagree. The changes in the CCA timeline made by this resolution are an exercise of authority the commission has had since 2002.”
Decision Adopts IRP Process
Another decision approved by the CPUC on Thursday sets RA requirements for all California LSEs. It institutes a two-year integrated resource planning process including electrical cooperatives, IOUs, CCAs and electric service providers.
The decision also recommends the state’s Air Resources Board adopt a greenhouse gas emissions target for the electric sector of 42 million metric tons by 2030, a 50% reduction from 2015 levels.
CPUC Delays Gas Moratorium Vote
In other items on the CPUC decision list, the commission tabled a proposal to require Southern California Gas to enact a moratorium on new commercial and industrial natural gas connections in Los Angeles County because of supply issues.
The CPUC said that while conservation measures by customers in response to the Aliso Canyon storage facility have helped, “significant new reliability challenges on the SoCalGas system exist due to a series of major unplanned outages and maintenance issues. The Los Angeles region faces greater uncertainty than a year ago with respect to the ability of SoCalGas to meet customer demand this winter.”
FORT LAUDERDALE, Fla. — The chairman of NERC’s Board of Trustees said last week the organization hopes to have a new CEO in place by the summer.
Roy Thilly told the Member Representatives Committee (MRC) during its Feb. 7 quarterly meeting that the selection process is “well underway,” with a goal for this spring.
“This is an important decision the full board needs to be involved in,” he said.
Russell Reynolds Associates has been conducting the executive search. Thilly said the board will select a group of about eight potential candidates, with a small group of trustees whittling that list down to two or three final candidates. The board will interview each of the finalists.
“Essentially, we want to be enthusiastic about the final candidate and have no hesitation that we have the right person for this job,” Thilly said. “If we don’t, then it’s important that we step back and take the time to do so.”
NERC has been without a CEO since Gerry Cauley resigned in November following his arrest for domestic abuse. General Counsel Charlie Berardesco stepped into the CEO role on an interim basis. (See Cauley Resigns; NERC Launches Search for Replacement.)
Thilly complimented NERC’s management team and staff for “really stepping up,” along with the Regional Entity CEOs.
“We feel like we’re in a good place right now,” he said. “The feedback I’ve gotten is that Charlie has stepped into the job in a seamless way and pulled the organization together.”
NERC also needs to hire a new chief security officer to replace Marcus Sachs, who resigned shortly after Cauley. (See NERC Parts Ways with Chief Security Officer.) Thilly said candidates have been “assembled,” but the agency won’t move forward until the new CEO is in place.
“It’s essential the new CEO participate in that hiring process and be very comfortable with the selection,” he said.
FERC’s McIntyre Says Resiliency Still of Interest in DC
FERC Chairman Kevin McIntyre told NERC trustees and stakeholders that the federal government still remains focused on grid resiliency, despite the commission’s rejection of the Department of Energy’s Notice of Proposed Rulemaking meant to address the issue. FERC launched a new resiliency initiative Jan. 8 after declining to take up the department’s proposal.
“Interest in that subject is not waning on [Capitol Hill], and it is not waning in the administration,” McIntyre said. “When real-world engagements occur with resiliency, like it’s old-fashioned cousin, reliability, we should use that as a teachable moment, and take lessons forward into the game plan and be better prepared for future events.”
McIntyre said the commission looks forward to working with NERC, and that it must remain “vigilant” in ensuring the grid’s resiliency, “a phrase you’ve no doubt heard.”
McIntyre and Berardesco were among several industry witnesses who recently testified before the Senate Energy and Natural Resources Committee about the January “cold-weather bomb.” (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
“Hanging in the air was the broader overall topic of grid resiliency,” McIntyre said. “I was very glad to be in a position to report that, based on various analyses, the bulk power system operated very reliably. My general impression was that my report, and those of the other witnesses, was well-received and appreciated in how well the grid performed.”
Resiliency is a priority at FERC, McIntyre said, and he expressed his gratitude to NERC for its work on the issue. He referenced the MRC’s Reliability Issues Steering Committee, which, at the trustees’ request, is developing a framework for resiliency.
The committee told stakeholders that most resilience definitions have two common elements: that it is “time-dependent” and differs from business-as-usual operations, and that it cannot be measured in a single-unit metric. It said the National Infrastructure Advisory Council’s framework for establishing critical infrastructure goals is a “credible source for further understanding and defining resilience.”
Bruce Walker, assistant secretary of the Energy Department’s Office of Electricity Delivery and Energy Reliability, said the department’s goal is to develop partnerships within the industry and provide resources to move issues forward.
“We have the opportunity to see the results of real work being done by FERC and NERC, and to shape policy through our coordination with both of these agencies,” said Walker, whose nomination was approved in October. “The [DOE] has stepped back to take a look at what our mission really is. It is … our mission-critical focus across the energy sector.”
Walker, formerly a deputy executive for Putnam County, N.Y., ran a boutique consulting firm focused on risk management at investor-owned utilities and served in leadership positions at National Grid and Consolidated Edison. He said his first goal is to develop a North American energy model “that integrates all different forms of energy so that we can run, like we do on our transmission system, a load flow.”
He said the bulk power system’s interdependencies will identify “those assets than can be enhanced, replaced or installed” to improve the system’s “affordability” as “we start moving forward” with the administration’s proposed $1.5 trillion infrastructure bill.
Other goals will focus on cyber and physical security, rapidly moving forward storage technologies, making use of sensing technologies and developing hardening strategies that add “some resiliency in a viable way.”
Jim Robb, CEO for the Western Electricity Coordinating Council, said recent developments within the Western Interconnection have put “substantial financial pressure” on Peak Reliability, the region’s delegated reliability coordinator (RC).
Within the past few months, Peak has announced it would team up with PJM Connext to attract participants to a new Western energy market. (See Peak, PJM Pitch ‘Marketplace for the West’.)
“Obviously, significant changes are going on that create a lot of uncertainty about how the ultimate reliability landscape will play out,” Robb said. He thanked FERC staff for working with WECC staff “as we move to a multiple RC model.”
NERC, WECC, British Columbia Agree to MOU
The board unanimously approved a memorandum of understanding between the British Columbia Utilities Commission (BCUC), WECC and NERC.
Modeled on recent MOUs with other Canadian jurisdictions, the agreement recognizes the parties’ roles under existing laws and authorities, maintains the status quo on funding arrangements, and provides for sharing of confidential and compliance-related information. WECC will periodically provide information on the Canadian province’s noncompliance for NERC’s review.
WECC General Counsel Steve Goodwill said a fully executed MOU should be in place in March, pending board approval from NERC and WECC.
NERC began formal correspondence with British Columbian authorities in 2006, while WECC has provided compliance monitoring for BCUC since 2009 through an administration agreement.
Goodwill said WECC is also negotiating similar terms with Mexico that recognize the changes in that country’s regulatory structure.
“Like the MOU with British Columbia, it will openly recognize for the first time the ability to share critical information on compliance enforcement in Mexico with NERC,” Goodwill said. “This is an all-around good story. The ability to share data among ourselves is critical.”
The MRC approved two new members and re-elected two incumbents to the board. Suzanne Keenan was elected to a two-year term expiring in 2020 and Rob Manning to a three-year term expiring in 2021, while George Hawkins and Jan Schori were re-elected to three-year terms also expiring in 2021.
Keenan served as CIO and senior vice president of process improvement for Wawa from 2008 to 2017. Her industry experience includes field services, re-engineering and performance, regulatory performance, and emergency preparedness experience with PECO Energy.
Hawkins, CEO of the D.C. Water and Sewer Authority, was first elected to the board in 2015. He serves on the Standards Oversight & Technology and Corporate Governance & Human Resources committees.
Manning was involved in transmission and distribution infrastructure research for the Electric Power Research Institute but will give up those duties with his election. He also spent six years with the Tennessee Valley Authority.
Schori, former CEO of the Sacramento Municipal Utility District for more than 14 years, was elected to the board in February 2009. She chairs the Finance and Audit Committee and serves on the Compliance and Enterprise-wide Risk committees.
