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.
DALLAS — SPP’s Regional State Committee last week accepted a working group’s proposal to leave unchanged the criteria used to exempt load-serving entities from transmission project costs in service requests.
The Cost Allocation Working Group recommended that no modifications be made to the thresholds used to determine what project costs should be borne by LSEs making long-term transmission service requests (TSRs). The RSC, composed of 10 regulators from across SPP’s 14-state footprint, accepted the proposal but then directed the CAWG to conduct annual reviews of the aggregate study safe-harbor criteria.
SPP’s aggregate transmission service study process combines all long-term point-to-point and designated network resource requests received during a specified time period into a single study.
The RTO splits the costs of transmission projects between the entire SPP footprint and LSEs purchasing transmission service for designated resources — those used to meet the LSE’s capacity margin requirement.
The safe harbor exempts LSEs from upgrade costs for a TSR when the aggregate studies’ waiver criteria are met:
Wind generation may not exceed 20% of designated resources.
TSRs must have a minimum five-year term.
Designated resources may not exceed 125% of forecasted load.
Utilities can also apply for an increase in the safe-harbor limit of $180,000/MW.
The CAWG approved the five-year and 125% thresholds unanimously, but it cleared the 20% wind limit by a 6-3 vote. Representatives from the Arkansas, Missouri and New Mexico commissions opposed the motion, while Iowa’s representative abstained.
Adam McKinnie, chief utility economist for the Missouri Public Service Commission and the CAWG’s chair, said he wanted to address wind energy’s operational issues in other ways than by determining who pays for which transmission projects.
“We felt something should be done, but I didn’t see this particular criteria as being the right tool for the job,” McKinnie said.
“Our state utilities had a lot of input to me on this,” said the Nebraska Power Review Board’s John Krajewski. “While I’m sympathetic and I understand the desire to eliminate this threshold, there are a lot of concerns with regard to the operations of thermal units and [SPP’s ability] to send proper signals to thermal units.”
Krajewski said the safe-harbor limits don’t prevent LSEs from adding wind above the 20% threshold. “If you exceed the threshold, then you would simply have to pay for any necessary transmission improvements,” he said.
McKinnie said the CAWG would next review and discuss the safe-harbor limit.
12% Planning Reserve Margin OK’d
The RSC also unanimously endorsed the Supply Adequacy Working Group’s recommendation to replace SPP’s capacity margin terminology with a 12% planning reserve margin requirement.
The revision request (RTWG-RR 187) was approved by the Markets and Operations Policy Committee in January. It incorporates previously approved policies that identify who is responsible for resource adequacy, the resource adequacy requirement and how and when the requirement should be met. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
The committee also made several personnel moves. RSC Chair Steve Stoll, a commissioner with the Missouri PSC, announced Commissioner Kim O’Guinn (Arkansas Public Service Commission) and Board Member Dennis Grennan (Nebraska PRB) have been added to the Regional Allocation Review Task Force to fill their states’ seats.
Committee members unanimously agreed to establish a nominating committee for future RSC elections and to work out the details during their annual retreat in July.
CMS Energy reported that 2016 was its best year for generation reliability ever, as it retired more than half of its coal-fired facilities and announced plans to terminate a nuclear plant power purchase agreement.
The Michigan-based company last year retired seven of its 12 coal-fired generation units, representing about 1,000 MW.
Palisades Nuclear Plant | Palisades Power
“Delivering operational success like this while at the same time transitioning our fleet so significantly requires a disciplined team,” CEO Patti Poppe said during a Feb. 2 earnings call.
The company boosted earnings for the year to $551 million ($1.98/share) from $523 million ($1.89/share) in 2015, although fourth-quarter earnings dropped to $77 million ($0.28/share) from $106 million ($0.38/share) a year earlier.
CMS plans to spend $18 billion over the next 10 years in capital expenses: $8 billion on gas infrastructure and maintenance; $4 billion on maintaining and building generation, including renewables; and $6 billion to upgrade its electric distribution. The company said it could spend an additional $3 billion on improving gas infrastructure, grid modernization, additional renewables and replacement of PPAs. Rate increases to pay for the capital improvements will be limited to 2%, CFO Tom Webb said.
Poppe said CMS will improve its financial position by terminating the Palisades nuclear plant PPA in favor of employing more energy efficiency, demand response, renewable power and coal-to-gas switching. (See Entergy, Consumers Announce Closure of Palisades Nuke.) According to CMS, the plan will save customers $172 million over four years.
Poppe said the substitute capacity plan for the Palisades PPA is “solid” and replaces a “single, big-bet capital project for many smaller options” with less risk. She said CMS could make more PPA replacements in the future by building new plants.
“We’ve long said that an inflexible, above-market PPA is not a cost-effective option for our customers and provides no long-term value for our investors. At the same time, we want to assure that we have sufficient resources to serve the load in Michigan,” Poppe said.
While year-over-year net income climbed about $300 million thanks to its Integrys acquisition, WEC Energy Group’s fourth-quarter earnings call focused largely on the company’s natural gas initiatives.
WEC reported net income of $194.4 million ($0.61/share) for the fourth quarter of 2016 compared to $179.3 million ($0.57/share) in fourth quarter 2015. Net income for the year was $939 million ($2.96/share) compared with $638.5 million ($2.34/share) for 2015, CEO Allen Leverett said during a Feb. 1 conference call. (See WEC Energy Shows $183M Profit After Integrys Deal.)
Leverett would not say whether the company plans to file a rate case with the Wisconsin Public Service Commission this year, saying only that its 2017 strategy is to keep rates flat while managing costs.
WEC projects 2017 earnings per share of $3.06 to $3.12, assuming normal weather. The company plans to continue its focus on natural gas distribution systems and infrastructure improvements.
The company signed an agreement Jan. 30 to acquire Michigan-based Blue Water Gas Holdings for $230 million. Blue Water, which owns an underground natural gas storage facility in Michigan, could provide up to one-third of the storage needs of WEC’s three gas distribution companies in Wisconsin through long-term service agreements as a subsidiary.
Leverett said WEC would file with the Wisconsin PSC for approval of service agreements for the storage. Leverett said the company chose the service agreements structure so the commission would not have to approve an out-of-state acquisition and WEC’s state-regulated companies would not be directly involved in an interstate natural gas business.
“I believe this investment will bring very meaningful customer benefits,” Leverett said, adding that there “certainly is room” for WEC’s own storage projects in the future.
UMERC Seeks OK for 2 Generators
New subsidiary Upper Michigan Energy Resources Corp. (UMERC) filed with the Michigan Public Service Commission on Jan. 30 to build two natural gas generating stations in Michigan’s Upper Peninsula. (See Michigan Upper Peninsula Getting its Own Utility.)
UMERC plans to pay about $275 million to build 180 MW of natural gas generation in two Upper Peninsula counties. If approved by the Michigan commission and MISO, construction will begin late this year or early in 2018.
“We are targeting commercial operation in 2019. At that time or soon after, we expect to be in a position to retire our coal-fired Presque Isle power plant. This should give significant savings in operations and maintenance expenses as well as reduce carbon emissions,” Leverett said.
Presque Isle Power Plant | WEPCo
WEC’s five-year capital spending plan has increased from $9.2 billion to $9.7 billion with the spending on natural gas storage and Upper Michigan’s new gas generation. Leverett said the revised plan does not include $1.7 billion of capital investments in subsidiary American Transmission Co.
On Jan. 30, ATC’s development company and Arizona Electric Power Cooperative entered a joint operating agreement to create ATC Southwest. The new transmission company will develop transmission projects in Arizona, California and other parts of the Southwest. “The largest opportunities outside of the footprint are in the West,” Leverett said.
ATC’s return on equity is still in flux, Leverett reminded shareholders. In September, FERC approved a 10.32% base ROE for MISO transmission owners. (See FERC Cuts MISO Transmission Owners’ ROE to 10.32%.) ATC qualifies for a 50-basis-point adder and is currently recognizing a 10.82% ROE. However, in another pending docket, the same FERC administrative law judge who first lowered the return said MISO TOs’ ROE should be lowered further to 9.7% (EL15-45). With adder points, the decision could bring ATC’s ROE to 10.2%. Leverett said he expects an order by the end of June even with former FERC Chairman Norman Bay’s resignation and the current lack of a commission quorum.
In a victory for wind energy advocates, FERC last week rejected SPP’s proposed method for measuring generators’ reactive power, saying it said would result in excessive and unnecessary costs (ER17-107).
The commission rejected the RTO’s October compliance filing in response to Order 827, which revised the pro forma large and small generator interconnection agreements to add reactive power requirements for all newly interconnecting nonsynchronous generators.
Smoky Hills Wind Farm in Kansas
Although the order required grid operators to ensure compliance by measuring reactive power at the “high-side” of the generator substation, SPP sought an “independent entity variation” allowing it to conduct measurements at the point of interconnection.
SPP said the variation was justified because its transmission system is dispersed over a wide geographic area and that many interconnection customers use longer generator lead lines to the point of interconnection to reach optimal parts of the transmission system.
The RTO said that measurements at the generator substation will not reflect “the charging or impedance” on the generator lead lines between that substation and the interconnection, creating a risk of excessive high and low voltages on the transmission system. SPP said that reliability standards would require the installation of reactive power compensation devices, at additional cost to transmission customers.
The proposal brought protests from several renewable generators and the American Wind Energy Association, which said the commission had considered the potential for long generator lead lines in their deliberations on Order 827. They also said SPP was not unique in having high-voltage nonsynchronous generator lead lines of 20 miles or longer.
The commission agreed, noting that Order 827 found that “requiring fully dynamic reactive power capability at the point of interconnection may result in significantly increased costs for nonsynchronous generators.”
Although setting reactive power requirements at the point of interconnection “would provide the greatest amount of reactive power to the transmission system,” the commission said, “the costs associated with providing that level of reactive power do not justify the added benefit to the transmission system.”
“In Order No. 827, the commission carefully considered the appropriate point at which to measure reactive power and ultimately found that ‘measuring the reactive power requirements at the high-side of the generator substation reasonably balances the need for reactive power for the transmission system with the costs to nonsynchronous generators of providing reactive power.’”
FERC also said SPP was not unique in its geography and had failed to provide information to support its reliability concerns. “Like SPP, other ISOs/RTOs have nonsynchronous generation interconnecting with the generator terminals located a significant distance from their point of interconnection. Similarly, SPP faces the same growing penetration of nonsynchronous generators as other ISOs/RTOs that in part resulted in the commission issuing Order No. 827,” the commission said.
It ordered the RTO to submit an additional compliance filing within 30 days.
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.
