FERC on Friday accepted PJM’s compliance filing on its fuel-cost policies for generating units but required the RTO to make another compliance filing to address a number of additional details (ER16-372-002).
The commission sided with PJM on several issues that have generated discussion at stakeholder meetings, including the relationship between the RTO and its Independent Market Monitor. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
“We agree with PJM that the proposed changes related to the fuel-cost policy are not designed to change the fundamental roles between the IMM and PJM, but rather to codify the role of the IMM in advising and providing input to PJM in its determination of whether to approve a fuel-cost policy submitted by a market seller,” the order read. “Accordingly, we reiterate our finding in the order that PJM has the final approval authority on fuel-cost policy.”
FERC declined PJM’s proposal that any differences between the RTO and its Monitor should be referred to the commission’s Office of Enforcement. That is the duty of administrative law judges, the order said.
The commission said the compliance filing, due in 30 days, should include:
PJM’s resource-dispatch formula and the process for determining the lowest-cost offer;
A broader description of which resources will be subject to mitigation;
The standard of review and an explanation of how a market seller would be found to be noncompliant with it;
specifics on when the penalty for a noncompliant fuel-cost policy would be terminated by the RTO, including a timeline with specific milestones;
A 90-day grace period before a new resource must submit its fuel-cost policy; and
A definition for when the penalty for noncompliance ends, along with a rebuttal period.
“We note that the penalty can still apply during the rebuttal time period, but if found to not be in violation of its fuel-cost policy, a market seller must be issued refunds as of the date of its rebuttal,” the order explains. “During this rebuttal period, if a market seller does not have a PJM-approved fuel-cost policy on file, it will still be required to submit a $0/MWh offer, but in the event that it is mitigated to its cost-based offer during this time period and its costs to operate, as per a PJM dispatch, are not covered by its market revenues, PJM should make the market seller whole by providing it with an uplift payment.”
A three-year dispute over cost and revenue sharing for a CapX2020 transmission project moved one step closer to resolution after FERC last week approved a settlement between the city of Rochester, Minn., and the Southern Minnesota Municipal Power Agency.
The dispute concerns the Hampton-Rochester-La Crosse 161-kV and 345-kV transmission line between Minnesota and Wisconsin, which is intended to meet swelling demand in the Twin Cities, Rochester and La Crosse, Wis., areas. Rochester’s Public Utilities Board (RPU) is a 9% owner in the project, which is part of the CapX2020 joint initiative by 11 Minnesota utilities.
The settlement approves revisions to MISO’s Tariff incorporating RPU’s existing facilities in Pricing Zone 20 (the SMMPA pricing zone); converting the RPU transmission rate formula to a forward-looking formula rate template with an annual true-up; and adding RPU to Pricing Zone 16 (the Northern States Power pricing zone) (ER15-277-004).
Still remaining is a dispute between Rochester and Xcel Energy, which is challenging RPU’s proposed recovery of its transmission revenue requirement for the project from Pricing Zone 16. The settlement does not resolve whether any of those costs should be allocated to Zone 20 if it is determined that the costs do not belong in Zone 16.
In a related order, FERC rejected Xcel’s requested stay on RPU’s rate recovery until the line was in service, saying a stay would amount to a “collateral attack” on the commission’s refund effective date (ER15-277-001). FERC agreed with MISO that Rochester’s facilitates were already figured into the Zone 16 revenue requirement when Xcel filed the motion for a stay. As the host transmission owner of six other TOs in Zone 16, Xcel subsidiary North States Power receives and distributes revenues allocated to Zone 16.
“To grant the stay now would require recalculating the Zone 16 transmission rate and providing refunds,” FERC said. “We are also not persuaded that a stay would leave all parties indifferent, as it would cause a delay in [Rochester’s] recovery of costs. … Granting the stay — especially if it lasted until the resolution of the ongoing dispute, as Xcel suggests — could endanger RPU’s ability to recover its transmission revenue requirement for the 2016 year.”
The commission also declined to place Rochester’s share of Zone 16 transmission revenues in an escrow account until a settlement is reached, as Xcel requested.
Xcel charged that MISO’s collection of Rochester’s estimated annual transmission revenue requirement associated with the line in Zone 16 from Jan. 1, 2016, was not justified because MISO did not begin dispersing transmission revenues to Northern States Power until October, when the line was placed into service. Rochester argued that as a MISO TO, it has the right to recover revenue requirements for transmission facilities under the RTO’s control.
In response to Xcel’s request, FERC also clarified that RPU will be subject to refunds if the commission upholds a reduction in the return on equity for it and other MISO TOs. In October, FERC ordered the TOs’ 12.38% base ROE cut to 10.32%. Rehearing requests in the case are pending (EL14-12). (See FERC Cuts MISO Transmission Owners’ ROE to 10.32%.)
The commission also opened a new docket (EL17-44) to examine the Zone 16 joint pricing zone revenue allocation agreement, ordering Xcel and other interested parties to file initial briefs within 30 days after the publication in the Federal Register. FERC also sought briefing on whether MISO’s joint pricing zone agreement can circumvent recovery of commission-accepted transmission rates. Tariff revisions could be necessary, FERC said, as Xcel argued it could not distribute those revenues to Rochester without violating the terms of its joint pricing zone agreement.
MISO’s three-year effort to identify long-term transmission needs started last week with the RTO gathering stakeholders to explain the data that will inform the study.
The regional transmission overlay study will identify new transmission needed to accommodate MISO’s shifting resource mix.
“MISO has been experiencing a significant resource change for quite some time now. … We’re just starting to get our hands around the magnitude of the needs,” Lynn Hecker, MISO manager of expansion planning, said at a special Jan. 31 workshop of the Economic Planning Users Group, the first of four scheduled to take place in 2017. “At the end of the day, the goal is to have the most cost-effective and efficient solution for our footprint to benefit our consumers.”
Hecker said MISO is very early into its study and has not made any conclusions about which or how many projects will be recommended. She said 2017 will be used to identify system needs, and project candidates would not be revealed until 2018 or 2019.
Three Futures
MISO will develop long-term transmission roadmaps for each of three 15-year futures from its 2017 Transmission Expansion Plan: an “existing fleet” future with limited changes and no modeled carbon cap; a “policy regulations” future in which federal rules drive a 25% reduction in carbon emissions; and an “accelerated alternative technologies” future in which innovations in renewables foster a 35% carbon emissions reduction.
| MISO
It will also consider other factors, such as the top 30 congested flowgates, forecasted differences in LMPs, production cost savings, and constrained energy sources and sinks to identify new transmission corridors. (See “Long-Term Overlay Study Scoped; MISO Asks for More Responses,” MISO Planning Advisory Committee Briefs.)
Stakeholders asked if MISO planned to use MTEP 17 futures for all three years of the study. Hecker said there would be an annual refresh of futures and weights to inform the study. “That’s where we are going to be able to capture any potential changes,” she said.
Hecker said it is likely that MTEP 17 futures will be used, even with the Trump administration’s plan to abandon the Paris Agreement on climate change and EPA’s Clean Power Plan. “We don’t expect to see very drastic changes in 2017 versus 2018 futures,” she said.
It’s still undecided if MTEP 17 futures will be reweighted with less emphasis on a policy regulations future. The issue is expected to be discussed at the February Planning Advisory Committee meeting. (See MISO Stakeholders Seek Review of MTEP Futures Under Trump.)
MISO Director of Regional and Economic Studies John Lawhorn said that by 2031, the RTO expects gas prices to hover around $7.50/MMBtu, with:
Between 5 GW of renewable additions under an “existing fleet” future to 52 GW in an “accelerated alternative technologies” future;
Coal generation retirements of 8 GW to 24 GW under the same scenarios;
An increase in solar capacity from 180 MW in 2016 to 4,938 MW by 2021; and
An increase in wind capacity from 16,319 MW in 2016 to 23,554 MW in 2021.
Move from Inventory-Based Generation
“We’re going from inventory-based sources of energy [like coal piles and natural gas storage] to non-inventory. We want to make sure we meet system needs both on a reliability and economic basis,” Lawhorn said. “Our generation interconnection queue is full of intermittents and continues to grow.”
Consultant Roberto Paliza of Indianapolis expressed concern that MISO might overlook some transmission solutions if it only relies on the megawatt limit in MISO and SPP’s contract path in modeling, which is in place until 2021. MISO staff pointed out the transmission overlay study is one of three MISO studies currently in progress that could identify a project to expand the transfer capability between MISO North and South. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs.)
MISO Policy Studies Engineer Matt Ellis said the economic benefit of load diversity — taking advantage of different areas peaking at different times — could be expanded beyond the RTO’s borders to include capacity exchanges with neighboring systems.
“If you can connect pockets of renewables across regions, you can make those resources look not so intermittent anymore,” Ellis said.
Ellis said he was only introducing the idea and that MISO would conduct discussions on how a load diversity analysis could work into the transmission overlay. He said while MISO could expand peak load obligations exchanges into the Eastern Interconnection, the RTO could also exchange capacity with the Western Interconnection if DC line upgrades are made. MISO estimated that load diversity could save it $4 billion per year.
Sam Gomberg, an energy analyst in the Midwest office of the Union of Concerned Scientists, asked if MISO sufficiently explored its own load diversity before looking outside the footprint. Ellis said the benefits of load diversity within MISO were already being realized with a reduced planning reserve margin.
An afternoon portion of the workshop, at which MISO and stakeholders discussed thermal constraint locations covered by Critical Energy Infrastructure Information (CEII) rules, was not open to the public. Stakeholders representing MISO’s North, Central/East, South and West regions split by region to discuss potential transmission needs. Bill Booth of the Mississippi Public Service Commission said his commission did not have access to CEII but still wanted in on the conversation.
Hecker said most study results would be made public, but detailed transmission maps with current bus and transmission line locations will not be posted publicly.
Lawhorn stressed the three-year study will be peppered with stakeholder opportunities to weigh in.
FERC on Friday granted New York officials’ request to exempt new “special case resources” (SCR) from buyer-side market power mitigation rules in NYISO (EL16-92).
The commission, however, denied a request to exempt SCRs currently subject to mitigation. An SCR is a demand-side resource that participates as a supplier in NYISO’s capacity market.
NYISO’s rules apply the minimum offer price rule (MOPR) to new capacity resources in the New York City or G-J Locality ICAP markets.
The Advanced Energy Management Alliance, the Natural Resources Defense Council and several New York state agencies, including the Public Service Commission, filed a complaint last June seeking the exemption. They said subjecting SCRs to NYISO’s buyer-side market power mitigation rules presents an “unreasonable barrier” for demand response providers that increases consumer costs and interferes with state policy objectives under the Reforming the Energy Vision initiative.
NYISO agreed with the complainants, saying mitigation was unwarranted because SCRs do not have the ability to suppress capacity prices.
FERC also agreed, rejecting arguments from the Independent Power Producers of New York and the Electric Power Supply Association that SCRs could have the same influence on installed capacity prices as other resources.
The commission said the argument is “based on the incorrect assumption that SCRs — which are generally individual or small aggregated sets of ‘resources’ — have the same ability to suppress ICAP market prices as a single, large market participant.”
Commissioner Norman Bay added a six-and-a-half-page concurring statement that questioned the overall efficacy of the MOPR. “I concur with this result but would go further in reconsidering the MOPR’s rationale and applicability in the wholesale electricity markets,” Bay wrote.
He appended a similar statement to another order on Friday that approved a MOPR exemption for renewable energy in ISO-NE. (See related story, Bay Blasts MOPR on Way Out the Door.)
The commission also ruled as moot a request for rehearing and its dismissal of a related NYISO compliance filing (EL07-39-007).
FERC on Thursday accepted PJM’s proposal to exempt transmission facilities that operate below 200 kV from its competitive proposal process (ER16-1335).
In April, PJM proposed the exemption, which designates the incumbent transmission owner to address such projects. The RTO then clarified in a compliance filing requested by FERC that all costs for such projects would be allocated to the single TO zone in which the transmission facility is located. (See “PJM Plans to Exclude Certain Upgrades in Order 1000 Upgrade Process,” PJM Planning Committee & TEAC Briefs.)
LSP Transmission Holding protested that PJM’s plan “removes competitive opportunities,” but FERC rejected the argument. The commission noted that PJM will identify transmission solutions for reliability violations on exempted facilities and include a transmission planning process that complies with Order 890.
“We deny [LSP’s] contention that the compliance filing unjustifiably removes competitive opportunities for transmission solutions to address reliability violations,” the order read. “The commission determined PJM’s proposal balanced the potential advantages of identifying, through the competitive proposal window process, the more efficient or cost-effective transmission solution to these particular transmission needs with the time and resources that PJM must expend to evaluate proposals submitted to address such transmission needs.
“The commission recognized that while there may be advantages to identifying solutions to some transmission needs arising from reliability violations on transmission facilities operating below 200 kV through a competitive proposal window process, PJM’s data demonstrated that the number of such cases (less than 1%) is de minimis as compared to the total number of reliability violations on transmission facilities operating below 200 kV.”
FERC last week approved SPP’s new rules for how it commits and pays “multi-configuration” combined cycle plants, an innovation that will also result in changes to settlement procedures for all generators (ER17-358).
Previously, the Tariff did not permit generators to offer multiple operating configurations. Combined cycle plants could register individual plant components as separate resources, register the plant as a single resource representing all the plant’s components, or register as a pseudo combined cycle resource (one combustion turbine and a portion of a steam turbine).
Under the new rules, SPP will be able to model up to three of a multi-configuration resource’s (MCR) operating configurations, providing additional flexibility for SPP’s commitment and dispatch of such plants.
The Tariff revisions also will affect SPP’s settlement practices for all resources, making changes to how the RTO determines make-whole payments, out-of-merit energy amounts and reliability unit commitment (RUC) make-whole payments. The RTO said the new rules “do not substantially modify eligibility for make-whole payments for non-MCRs, but instead more accurately reflect cost causation principles in the calculation of make-whole payments.”
In approving SPP’s proposal, the commission said the changes “will more accurately model the operating characteristics” of flexible combined cycle plants. “In addition, we find that SPP’s proposal to modify its market settlement procedures for both MCRs and non-MCRs will more accurately reflect commitment optimization and cost causation principles in cost recovery and thus benefit market efficiency.”
The commission ordered SPP to make a compliance filing clarifying how it will “ensure MCR configurations, when mitigated, reflect the lowest cost unit capable of participating in the configuration.” The commission said revisions proposed by SPP “should also inhibit physical withholding by requiring one valid configuration to represent the maximum capacity of the combined cycle resource.”
The changes are effective March 1, when software allowing the modeling of the MCRs goes live. Participants completed testing of the software in January.
WASHINGTON — It was Congress on its best behavior, for a change.
The House Subcommittee on Energy met Wednesday for the latest in its hearings on cybersecurity in the electric industry. It was a sober, reasoned discussion, in a bipartisan spirit almost unimaginable amid the anger roiling Capitol Hill over President Trump’s candidates for the Supreme Court, EPA and other cabinet offices.
“Downstairs we’re fighting like cats and dogs, but in this subcommittee, on this issue, we’re hugging each other,” said Rep. Joe Barton (R-Texas).
The subcommittee’s nearly two-and-a-half-hour session wasn’t a complete cease-fire zone. Rep. Frank Pallone (D-N.J.) railed over Trump’s decision to add controversial political strategist Stephen Bannon to the National Security Council’s Principals Committee while “apparently” excluding the secretary of energy. This, Pallone said, despite Congress’ approval of legislation two years ago to make the secretary the lead federal official responsible for electric grid security.
“Essentially, President Trump has chosen his top political security adviser over the nation’s top energy security adviser — and that’s a recipe for disaster,” Pallone fumed.
But that was the exception, as a panel including NERC CEO Gerry Cauley brought the panel up to speed with discussions of the 2015 attack on utilities in Ukraine, the discovery of malware on a Vermont utility’s laptop and the cybersecurity talent pool.
“The reliability of the bulk power system has improved over the last 10 years,” Cauley said, citing data on the number and severity of outages. “We’re always learning from every single event: small, medium and large.”
Cauley’s other panelists — SPP Vice President for Information Technology and Chief Security Officer Barbara Sugg; Scott Aaronson, the Edison Electric Institute’s executive director for security and business continuity; and Chris Beck, chief scientist and vice president for policy for the Electric Infrastructure Security Council — generally agreed. In response to a question from Barton, all graded Cauley’s leadership an “A.”
But Rep. David McKinley (R-W.Va.) was unconvinced.
“We’ve been told that ‘Everything is going to be fine. Everything’s under control,’” McKinley said, recounting hearings he has attended over his six years in office. He quoted UCLA basketball legend John Wooden’s admonition against confusing effort with accomplishments.
McKinley also repeated testimony two years ago by Thomas M. Siebel, founder of Siebel Systems, who said he and a team of 10 engineers from the University of California Berkeley could shut down the grid between Boston and New York within four days. “Now that was after all the testimony about all the safeguards we had in place. So is Mr. Siebel wrong?” he asked.
“I don’t think any of us today are saying it’s 100% under control,” responded Aaronson, speaking on behalf of the Electricity Subsector Coordinating Council. “While an attack that has an impact is always within the realm of the possible, the resiliency and redundancy that has grown up, and the ability to respond … makes me a lot more comfortable in our ability to deal with these sorts of [threats].”
A recurring theme in the panel’s comments was interdependence. They cited generators’ need for cooling water, the use of trains and trucks to transport spare transformers, and grid operators’ reliance on the telecommunications and financial services industries.
“I don’t ever expect there’s going to be an attack that’s just on the grid,” said Cauley, who added that the electric industry must increase its coordination with other sectors.
Beck agreed. “Simultaneous attacks on the oil and natural gas subsector, on water systems, communications, government, emergency response or other infrastructures could both create new categories of severe disruption and seriously complicate power restoration operations,” he said in his opening statement.
“In the aftermath of a natural disaster, response activities typically commence once the immediate danger has passed. In a cyberattack scenario, it is possible, or even likely, that the attacker could launch subsequent attacks to disrupt response and recovery efforts and/or cause further damage.”
Information technology and operational technology “professionals, however, are typically a limited resource. In a large enough attack, availability of such expertise will likely be too limited to address the need. In addition, especially given the problem of sustained or follow-on cyberattack, CEOs may be reluctant to flow critical personnel to assist others when they might be the next target. To bolster the intra-electric sector mutual support, external support is also necessary.”
The speakers also cited concerns over the supply chain for equipment used on the grid and “Internet of Things” consumer devices that could be vulnerable to hackers.
“I think we should put more emphasis on the manufacturers and really hold them accountable for developing things that are easy to maintain security with — not things that you just plug in and forget about,” said Sugg, representing the ISO/RTO Council. She said that certification of equipment could help.
“We used to buy a relay for the system and it would just be a couple of contacts and a core of copper wire,” said Cauley. “Now you have a box and it has 10,000 lines of code,” making them vulnerable to being reprogrammed by hackers. “So I think we have to think about long-term partnerships with suppliers, vendors and manufacturers in terms of building better security into systems.”
Fast Act
In response to lawmakers’ questions, the panelists said they welcomed the Fixing America’s Surface Transportation (FAST) Act of 2015, which amended the Federal Power Act to designate the Energy Department as the lead federal agency for energy sector cybersecurity. It also gives the secretary of energy authority to take emergency actions to protect the grid.
Cauley said the law corrected the lack of clarity on how the federal government would respond in a grid security emergency and increased protection of sensitive information. To comply with the law, FERC in November approved a rule updating its processes for the handling of Critical Energy Infrastructure Information (CEII). (See FERC OKs Information Security, FOIA Rules.)
Aaronson said the law “further solidifies the relationship” between industry and the federal government.
Pros and Cons of Distributed Generation
In response to a question from Rep. Jerry McNerney (D-Calif.), Cauley said he was “deeply concerned” about distributed generation, saying that while it can provide resiliency to the grid, its equipment is more vulnerable to hacking. In October, major websites were hit with a distributed denial-of-service attack that used thousands of Internet-connected devices such as cameras, baby monitors and home routers.
“The challenge is that all the devices are communicating with something else, and in some cases they’re much closer to the Internet than the bulk power grid,” he said. “So it’s going to create a much greater surface to attack and create multipliers in the attack. When you have common devices that are out there, instead of there being three breakers of a certain model, there’s 1.5 million devices that are exactly the same and could be simultaneously hacked.”
The panelists also commented on several other recent incidents, including the April 2016 power outage in D.C., the December 2015 attack on utilities in Ukraine and the discovery of malware on a utility’s laptop in Vermont.
The power outage that darkened the White House and much of D.C. on April 7 was caused by the failure of a 230-kV lightning arrester at a substation 40 miles south of the capital. (See Failed Lightning Arrester Caused April Outage.)
Aaronson recalled that in the first hour after the lights went out, the cause was unclear. He said Pepco Holdings Inc. officials got on the National Incident Communications Conference Line with the Department of Homeland Security and White House officials, allowing the White House press secretary to announce that it was not the result of terrorism.
He said a real cyber incident would result in “immediate high-level coordination between the ESCC and industry CEOs along with senior government and NERC officials and the team from the Electricity Information Sharing & Analysis Center, which manages the Cybersecurity Risk Information Sharing Program.
When a Vermont utility found malware associated with Russian hackers on a laptop in December, Aaronson said, 30 top utility CEOs were on an emergency conference call within four hours. “That is exactly the way it’s supposed to happen,” he said.
Ukraine
Cauley expressed confidence that the utilities under NERC’s authority would not have fallen victim to the attack that knocked out power to 225,000 customers in Ukraine for several hours in December 2015.
The hack had been set in motion in the prior spring, when attackers entered three Ukrainian electric distribution companies through infected Microsoft Office files. After gaining entry, the hackers spent six months conducting reconnaissance and testing before taking control of the systems in late December. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)
Cauley acknowledged that the spear phishing technique used to get into the utilities in Ukraine is “the greatest vulnerability we have.” But he said the attack would not have been successful here.
“We would not allow that software to go unchecked and for the perpetrators to get elevated credentials so they could actually operate the system. Those are extreme violations of all our rules,” he said.
Rep. Bobby Rush (D-Ill.) asked whether the industry was having trouble attracting talent to its mission, citing an estimate by the Institute of Electrical and Electronics Engineers of 1 million unfilled cybersecurity engineering jobs worldwide.
“It’s a challenge. There are a lot of needs and not a lot of people to fill it,” Aaronson acknowledged. “This is something that’s going to require a long-term, concerted effort, starting with STEM [science, technology, engineering and math] education and moving up to attracting the workforce to this particular critical infrastructure industry.”
Sugg said the industry is addressing the problem by partnering with universities to develop relevant curriculum. “Universities are producing some really skilled graduates that challenge our way of thinking about security in a very healthy way,” she said.
Beck said another challenge is breaking down communication barriers resulting from “stove pipes and tunnels.” Stove pipes — or silos — can inhibit communication between government agencies and infrastructure sectors. Tunnels refer to the levels of decision-making.
“So CEOs understand each other and they have a certain view of the situation. The engineers that work on cybersecurity have a different understanding,” he said. “We need to … break down both silos and tunnels so that there’s a common operating picture and mission.”
FERC last week rejected Big Rivers Electric’s request for a waiver to keep MISO interconnection rights for one of its coal plants through late 2017.
Big Rivers was seeking to keep its Coleman Station in Kentucky interconnected to MISO’s grid for an additional year after the RTO ended a three-year system support resource agreement for the 433-MW coal plant in September. After that, the company said it would file another interconnection termination waiver request in August 2017 while it decides whether to restart the plant with environmental upgrades or convert it to natural gas. Big Rivers also said it was waiting on a MISO compliance filing regarding the retention and transfer of interconnection rights of a retiring SSR. (See FERC OKs Change to MISO SSR Process.)
Coleman Station | Big Rivers
FERC denied the request on the grounds that projects in MISO’s interconnection queue could be impacted by the waiver and Big Rivers’ stated intent to file a waiver extension would mean the requested waiver would not be limited in scope.
“Because MISO indicates that at least one project in its interconnection queue could be affected by granting this waiver request, we cannot conclude that granting Big Rivers’ request would have no undesirable consequences,” FERC said in its Feb. 3 order (EL17-15).
The commission said Big Rivers’ indecision on whether to restart Coleman “directly contradicts” its claim that it has taken “significant steps” to restore the plant to commercial operation soon. FERC also pointed out that an interconnection rights transfer would not apply to Coleman because it exhausted the maximum 36 months of suspension/SSR designation that MISO allows in a five-year period and could no longer sit idle and stay connected.
Big Rivers had argued that terminating Coleman’s interconnection service would harm regional reliability and increase costs for its members. The cooperative said it spent $6.5 million in 2014 to idle Coleman and spends $2.8 million every year to preserve the plant. FERC said Big Rivers’ expenses are merely to maintain the coal station’s “existing state” and not enough to return it to commercial operation, as the plant would violate EPA’s Mercury Air Toxics Standards and need environmental improvements.
Finally, FERC brushed aside Big Rivers’ arguments that terminating interconnection service would run counter to language in MISO’s generation interconnection agreement. FERC pointed out that Big Rivers never had a generator interconnection agreement with MISO.
After SPP staff and stakeholders presented alternative proposals Wednesday to improve the process in which members are assigned financial credits and obligations for sponsored upgrades, the only consensus was that more time is needed. Eight years of applying the credits incorrectly has complicated the task of trying to properly compensate project sponsors and claw back money from members that owe debts for the upgrades.
“I don’t think there’s a single proposal that addresses everything in the way we want to,” said Kansas City Power and Light’s Denise Buffington, the task force’s chair. “I think we’re going to have to cherry-pick what’s important. Concepts are important, and knowing what concepts would be nonstarters for you would be helpful.
“We don’t have the option of doing nothing,” she said, reminding the task force of its charge from the Board of Directors.
Sunflower Electric Power’s Davis Rooney suggested developing a matrix of the proposals’ elements to gain a better understanding of which pieces will be kept and which will be discarded.
“Are we retaining or not retaining the safe-harbor limit? The wind rule … the highway/byway” transmission-cost allocation rule? he asked. “Some of those questions seem pretty common across the proposals.”
“This has to be a package for us,” countered The Wind Coalition’s Steve Gaw. “Seeping little elements out, agreeing to take this out and that out … that will create a challenge. The idea that you have a set funding stream on capacity upgrades and you will get reimbursed over time … that might have some attractiveness to it.”
Some stakeholders expressed a preference for using transmission congestion rights (TCRs) or incremental long-term TCRs, while others suggested following a staff proposal to create a new schedule under the SPP Tariff. Staff is already digging through FERC orders to see how the RTO might justify Tariff changes, and it is soliciting input from MISO and PJM on how they allocate the cost of upgrades.
Meena Thomas, a senior market economist with the Public Utility Commission of Texas, said the state regulators’ Cost Allocation Working Group would be unlikely to accept any increase in base-plan funding as part of any rule change.
“Based on discussions at the CAWG, they have a concern,” Thomas said.
Staff proposed replacing the Tariff’s Attachment Z2 with a separate Schedule 13. SPP’s Charles Locke said the new schedule’s charges would fund all upgrade sponsors’ credit payments and would apply to all network and point-to-point customers.
“A separate schedule might be cleaner and less complex in both administration and Tariff structure,” Locke said.
He said the charge could either be a regionwide charge or a combination of regionwide and zonal charges. The rate would be revised periodically, he said, possibly through an annual formula update.
Under the Schedule 13 proposal, Locke said, the entire facility cost would not be “simply” rolled into rates, instead being limited by the extent to which the facility is used for transmission service. He said the proposal would address legacy Z2 balances and eliminate directly assigned upgrade costs in the future.
Barraged by questions about his proposal, Locke injected some levity into the discussion. “Just to clear things up, I’m going to throw some calculations on the board,” he said to laughter.
The staff proposal had its supporters. “I’d like to see where Schedule 13 goes,” said the Kansas Power Pool’s Larry Holloway. “[I’d like to know] how material are the dollars that fly around and some idea of how big it is.”
American Electric Power’s Richard Ross proposed an approach he said was “fair, reasonable and efficient.” He focused on sponsored network upgrades, saying the current approach has been to view the projects as “new construction,” but that they should be viewed as economic projects.
Ross suggested continuing to calculate revenue credits for long-term service and regionally funding the costs while eliminating the short-term revenue credit calculations and grossing up other credits by 2%. He said existing sponsorships should be handled the same way.
“The process would eliminate the invoicing and stop the proliferation of new project sponsors and their associated accounting,” Ross said.
Dennis Reed, a recent Westar Energy retiree and now a consultant with his Midwest Regulatory Consulting firm, had his own ideas. He proposed eliminating short-term TSR credits to reduce the number of new upgrade sponsors but leaving the rest of the TSR-upgrade process the same.
Reed suggested creating a 20-year payback schedule for only those generation interconnection (GI) upgrades that create available transfer capability (ATC) and giving ILTCRs for sponsored upgrades, which must still meet the current need test.
“The basic goal is to minimize the work staff has to do,” said Reed, alluding to the processing of short-term service requests, which account for about 2% of all Z2 work.
Reed said his proposal would reduce the number of future upgrade sponsors and give GI customers a guaranteed payment schedule for all upgrades that provide added ATC. It would also lower costs to transmission customers because most upgrades that do not increase ATC — generally for switches and enhanced control systems — are not eligible for payments, he said.
“A builder of a sponsored upgrade will know the possible value of any upgrade it builds,” Reed said.
Xcel Energy released fourth-quarter and year-end earnings results Thursday, beating investors’ expectations for earnings per share by a penny but missing their fourth-quarter revenue forecasts by hundreds of millions of dollars.
Minneapolis-based Xcel said it earned $227.5 million ($0.45/share) during the fourth quarter, up from $209 million ($0.41/share) for the same period last year. Zacks Investment Research’s consensus estimate was 44 cents/share.
At the same time, the company reported fourth-quarter revenue of $2.8 billion, up from $2.65 billion a year ago, but short of the expected $3.5 billion. Xcel laid the blame on warmer-than-expected weather.
Xcel Energy wind farm | Xcel Energy
CEO Ben Fowke called 2016 an “excellent year” in a press release Thursday. During a later conference call with analysts, he said, “I don’t think the quarter is indicative of where we think trends will go. We are seeing good customer growth in Colorado and Minnesota and other jurisdictions.”
Fowke said the company plans to invest $3.5 billion in its “steel-for-fuel” strategy, taking advantage of ample wind resources in Colorado and the Dakotas. Xcel completed its first project, the 200-MW Courtney Wind Farm, as a general contractor in North Dakota last year. Regulatory approval in hand, its 600-MW Rush Creek project in Colorado is expected to go into service in 2018.
Xcel is also adding 1,500 MW of wind in Minnesota through power purchase agreements and another 750 MW through “self-build” proposals, in which as owners, the company will benefit from 100% of the production tax credit and “maximize the fuel savings” for customers. Fowke said the company has received 95 proposals from 17 bidders for almost 10,000 MW wind generation and will soon file for regulatory approval.
The company is embroiled in a regulatory and legislative tug-of-war in Minnesota over plans to retire two 680-MW coal units by 2026 at its Sherco plant northwest of Minneapolis. The Minnesota Public Utilities Commission in January opened a docket over Xcel’s plans to build a 780-MW combined cycle natural gas unit as a replacement, but a state legislator has since filed a bill that would give the company authority to construct, own and operate the unit without obtaining PUC approval.
Sherco Generating Station | Xcel Energy
“The bill was driven by legislators who are concerned about the loss of jobs and tax revenue and wanted to expedite the decision process,” Fowke said. “It’s important to note we have provided extensive justification for the plant, and the commission will still need to approve cost recovery.”
Fowke said any capital investment for the project, expected to cost more than $1 billion, “will likely” happen after 2021.
The company raised its dividend by 6.3% to $1.36/share, the 13th straight year it has increased it. Fowke also noted Xcel met or exceeded its earnings guidance for the 12th straight year. Its stock price closed up 83 cents at the end of the week, to $41.45.
Xcel reaffirmed its 2017 earnings guidance of $2.25 to $2.35/share.
Xcel Energy released fourth-quarter and year-end earnings results Thursday, beating investors’ expectations for earnings per share by a penny but missing their fourth-quarter revenue forecasts by hundreds of millions of dollars.
