PG&E Corp. on Friday offered the most detailed versions yet of its plans to emerge from bankruptcy in filings with the California Public Utilities Commission and the U.S. Bankruptcy Court in San Francisco.
The company said its updated Chapter 11 reorganization plans address the concerns of Gov. Gavin Newsom, whose opposition may be the last major obstacle to it emerging from bankruptcy mostly on its own terms. The CPUC, whose members are appointed by the governor, must find the plan complies with the safety dictates of Assembly Bill 1054, passed last July.
“PG&E has taken to heart the governor’s concerns, and the PG&E plan and accompanying testimony commitments embody the governor’s principles and more than satisfy the requirements of AB 1054,” the company told the CPUC.
The bill sets up a $21 billion wildfire recovery fund to insure the state’s investor-owned utilities against future wildfires. PG&E must comply with its requirements, including safety improvements, to take part in the insurance fund.
Whether the company’s revised plans go far enough to mollify Newsom remains uncertain.
PG&E says its crews are working to inspect and harden lines to prevent wildfires. | PG&E
Newsom has asked for major concessions from PG&E including a new board of directors made up mostly of Californians. He also wants PG&E’s Chapter 11 plan to incorporate a mechanism allowing for a quick state takeover if warranted.
PG&E’s updated plan does not provide the takeover mechanism, nor does it agree to Newsom’s demand for a new board with a majority of directors from California.
Instead, Nora Mead Brownell, a former FERC commissioner and chair of PG&E’s corporate board, noted in prepared testimony to the CPUC that the company initiated a “board refreshment” last year that replaced almost all its directors and those of its utility subsidiary, Pacific Gas and Electric.
That process brought in Brownell and Johnson, the former head of the Tennessee Valley Authority, among a dozen others.
“The board refreshment brought to PG&E fresh perspectives, and a range of diverse backgrounds, experiences, skills and expertise,” Brownell told the commission.
The company said it is reviewing its “director skills matrix” to make sure board members have experience in fields such as wildfire safety, utility operation and risk management. It also plans to incorporate independent safety oversight and to tie executive compensation to safety performance, among other measures.
PG&E’s Wildfire Safety Operations Center monitors conditions in which power lines could ignite wildfires. | PG&E
Brownell said Californians already make up about 40% of the current board, but “PG&E will use best efforts to achieve a target of at least 50% California resident directors upon emergence” from bankruptcy.
The plan also complies with the state requirement that the plan not impose higher rates on PG&E’s 5.4 million electric customers.
Newsom’s office offered no comment on the changes over the weekend but told The Wall Street Journal he was reviewing them. Quoting an unnamed source, The Sacramento Bee reported that the updates were the product of back-channel negotiations between PG&E and the governor’s staff.
PG&E indicated in a statement that it could participate in additional negotiations.
“PG&E appreciates the governor’s input and is open to further discussions with the governor’s office and other stakeholders should they have additional input as the process unfolds,” it said. “PG&E looks forward to participating fully in the CPUC’s proceeding to review its updated plan.”
Newsom’s comments toward PG&E have become increasingly harsh in recent months, with the governor issuing repeated threats that the state could take over the utility if it doesn’t adopt wholesale changes including all-new leadership and a new corporate safety culture. (See PG&E Chapter 11 Plan Won’t Do, Governor Tells Judge.)
The utility has been blamed for safety lapses that resulted in catastrophic wildfires in 2015, 2017 and 2018, and a deadly gas pipeline explosion in 2010.
“We’re sick of the excuses, the delays,” Newsom said last week in a forum on energy with the Public Policy Institute of California.
Newsom said he’s been working with legislative leaders to have a structure in place to seize control of the utility if it doesn’t meet his expectations for change before it exits bankruptcy. “What is PG&E? It’s a corpus. It’s an entity,” the governor said, describing frequent changes in recent years to the company’s executives and directors. “The entity exists on paper only. But there’s a culture there that transcends. And until that mindset radically reforms itself, then the state of California is poised to take it over.”
SPP’s Marketing Monitoring Unit has scheduled a pair of webinars over the next two weeks to discuss reports it has recently released.
On Monday, the MMU will host a webinar at 2 p.m. to discuss a self-commitment report released in December, “Self-committing in SPP markets: Overview, impacts, and recommendations.”
According to the report, the volume of self-committed generation has declined over time but remains nearly half of the recent megawatt volume. Self-committed generators had lower revenues because of negative congestion prices, whereas market-committed generators typically had both positive and negative congestion prices, and resources with long lead times and/or high start-up costs tend to be self-committed instead of market-committed, the MMU found.
Percentage of MW dispatched by commitment status | SPP MMU
The MMU recommends that SPP and its stakeholders work to reduce the number of self-commitments, therefore improving price formation and market efficiency.
The Monitor has also scheduled a webinar on Feb. 10 to discuss its quarterly State of the Market report for September through November.
The report indicates higher temperatures pushed the average hourly load up as much as 10% during the fall months. It also says wind generation saw a 44% increase over 2018.
The report also includes a special issues section on a rate pancaking and an unreserved use study published in November for work being done by SPP and MISO regulators.
2020 is shaping up to be a seminal period in the Midwest’s transition to renewable energy if new initiatives and state legislation are any indication.
“The trends are largely positive,” James Gignac, lead Midwest energy analyst with the Union of Concerned Scientists (UCS), told RTO Insider.
“We’re hoping to hear some plans for additional climate and energy action,” Gignac said, adding that the region’s state utility commissions are particular hotspots of clean energy activity.
Global research nonprofit World Resources Institute predicts 2020 will be a watershed year for clean energy goals in the U.S., with cities signing “unprecedented utility-scale clean energy deals.” (See related story, US Renewable Investment Hits Record $55.5B.)
The Sierra Club notes that nearly 160 cities have committed to 100% renewable energy. Fifteen states plus D.C. and Puerto Rico have recently made commitments to get more than 50% of their energy from clean resources by 2050 or earlier. In the Midwest, Wisconsin is so far the only state to have finalized a 100% target by that year — but its days of being a regional outlier in clean energy targets are dwindling.
Last year, lawmakers in Illinois, Iowa, Michigan and Minnesota introduced bills containing new renewable energy targets.
In Minnesota, the Senate last year demurred on Gov. Tim Walz’s proposal to transition to 100% zero-carbon energy by 2050. But senators are now considering the Clean Energy First Act, which would direct utilities to prioritize carbon-free resources in their planning and require the Public Utilities Commission to consider whether utilities’ proposed generation is in the public interest.
The Illinois legislature is considering the Clean Energy Jobs Act, a possible successor to 2016’s Future Energy Jobs Act. The new bill requires 100% carbon-free electricity by 2030 and 100% renewable energy by 2050. Gignac said the bill recognizes the existing nuclear generation in the state.
“One of the key factors as states are considering 100% energy goals is including interim goals, like 2030 and 2040 targets, to ensure progress is being made toward the long-term goal,” Gignac said.
Illinois Gov. J.B. Pritzker and Michigan Gov. Gretchen Whitmer both delivered State of the State addresses Wednesday that emphasized environmental issues.
Pritzker said “clean energy legislation that reduces carbon pollution, promotes renewable energy and accelerates electrification of our transportation sector” would be a priority of his administration in 2020.
In October, Whitmer and the Michigan Public Service Commission launched MI Power Grid, a multiyear effort to help guide the state through its transition to more clean and distributed energy solutions.
The state goals may be born of necessity.
A recent Moody’s Investors Service report on climate risk concluded that Midwestern generators are the most susceptible to intense heat waves and flooding, while Southeastern generators will be more at-risk from hurricanes. Western operators could grapple with water shortages.
The report drilled down to specifics: AES subsidiary Dayton Power and Light will be particularly subject to flooding; Ameren territories across Illinois and Missouri are most vulnerable to rising temperatures; and Xcel Energy’s territories in Colorado, New Mexico and Texas most susceptible to water shortages. NextEra Energy, Dominion Energy and Duke Energy were called out for significant hurricane risk.
Ameren has said it will cut its emissions to 80% below 2005 levels by 2050 and will counteract effects of climate change on its equipment by improving its flood mitigation infrastructure, burying some transmission lines and installing more insulation on lines.
UCS last year also predicted increasingly frequent extreme heat events in the Midwest. “Even with aggressive action, the number of days per year with a heat index above 90 degrees F would more than double for both the Midwest and Northern Great Plains, to an average of 56 and 32 days per year, respectively. The number of days with a heat index above 100 degrees F would triple or more to an average of 22 and eight days per year, respectively, for each region.”
But Gignac says the flurry of activity in the Midwest so far has been driven by economics, not climate hazards.
In October, Wisconsin Gov. Tony Evers created a task force on climate change. However, state regulators recently approved Dairyland Power Cooperative and Minnesota Power’s controversial 625-MW gas-fired Nemadji Trail Energy Center in Superior. The $700 million generator, which will serve customers in Minnesota and Wisconsin, was authorized for construction despite concerns about its environmental impact. The Minnesota PUC likewise approved the plant in 2018, but in December, a state appeals court ordered the commission to conduct a further environmental impact assessment.
Closer Look at Natural Gas
Gignac said the replacement of aging coal plants with large gas-fired units remains a cause for worry for UCS in Midwestern states.
“It’s a big concern as many utilities are phasing out their coal plants. Utilities are approaching that issue in different ways,” he said.
Consumers Energy, for example, plans to use a combination of solar, demand response and energy efficiency to avoid new gas plants.
Gignac urged that state commissions and other stakeholders take “a careful look at the economics of natural gas in this transition,” instead of “locking in” long-term investments in fossil fuels.
“That’s the risk with natural gas plants. They could become stranded costs. The fuel cost is a variable, and renewable energy is continuing to get cheaper,” Gignac said.
He also pointed to DTE Energy’s integrated resource plan pending before Michigan regulators. In December, Administrative Law Judge Sally Wallace issued a proposed decision against the IRP, saying it relied on outdated data and modeling that understated the benefits of renewable energy and energy efficiency. The plan relied too heavily on gas generation and failed to solicit bids for new renewable generation, Wallace ruled, adding that DTE should alter its plan even if the Michigan PSC approves the original version. (See DTE IRP Draws Fire from Renewable Proponents.)
“The next step is to see how the commission handles the proposed order,” Gignac said. “We’re hopeful that the commission would largely agree with the order and ask for a number of changes in a revised plan.”
The PSC will meet Feb. 20 to consider the IRP.
Scrutiny on Self-scheduling
UCS has also criticized DTE’s IRP for its reliance on self-scheduled coal generation.
“Traditionally, coal plants were built and designed to run year-round. However, as lower-cost resources such as wind and solar have come onto the market, there are periods during the year where it doesn’t make sense to operate coal plants. That’s what driving the re-evaluation into self-scheduling,” Gignac said. (See Enviros, States Question Coal Self-commitments.)
Xcel filed a petition in December to convert two of its four coal-fired units to seasonal and economic use instead of self-scheduling them. The utility said it would idle its Allen S. King and Sherco Unit 2 generators during the spring and fall, and only offer them into the MISO markets when they are profitable, saving ratepayers up to $55 million in fuel, operations and capital costs between 2020 and 2023.
“That’s a key recognition of the changing market and re-evaluation of how coal plants are running … so that customers aren’t facing unnecessary costs,” Gignac said of Xcel’s proposal.
“This is getting a lot of attention in a lot of states,” Gignac said.
It’s “key” that utilities continue to examine supply solutions for peak demand days, he said. “We want to continue to use renewables, demand response and energy efficiency to replace dirty fossil fuels during those periods.”
The Economics
Speaking last week in Des Moines, Iowa, on a panel focusing on climate change and wind generation’s enduring popularity, Jeff Danielson, the American Wind Energy Association’s Central States director, said clean energy transitions can occur even absent state policy.
Jeff Danielson, AWEA
“I think what’s really cool about Iowa’s leadership in wind energy is that there was never really a mandate. … A lot of this growth has been without mandates,” said Danielson, calling Iowa’s first 105-MW renewable energy goal in 1983 a “mini RPS.”
Iowa has a sparse history of obligatory clean energy rules. That first renewable portfolio standard didn’t have a clear enforcement provision and wasn’t required until 1996 by the Iowa Utilities Board. Iowa’s governor in 2001 established a voluntary 1,000-MW goal for wind capacity by 2010. Today, Iowa is second to Texas in wind generation, with nearly 9 GW of installed wind capacity at the end of 2019.
Danielson said Kansas, North Dakota and other Midwest states are primed to follow in Iowa’s footsteps of voluntary wind buildout.
“We have an opportunity to take lessons learned from Iowa, to export them, if you will, politically and policy-wise to those other states,” Danielson said.
But Gignac said energy policy at the state level ensures that renewable transitions continue and provides market certainty to investors and developers.
“It’s true that market forces are helping drive a transition to clean energy, so that’s a good thing, And I think it will continue. But we should also recognize that state clean energy policies have helped increase deployment of renewables and brought them to scale to reduce costs,” Gignac said. “State renewable energy policies are an important backstop and can also provide market certainty to developers. They help chart the long-term growth of renewables.”
Danielson said it’s no longer a question of wind energy doubling in capacity.
“The real question is will it triple and quadruple,” he said, noting that wind energy is becoming economic even without subsidies.
“Almost all forms of energy are subsidized in some way. Wind energy is prepared to go without subsidies,” Danielson said. “Regardless of your local culture or your local politics — red state, blue state — what we know is that there is a unifying factor around wind energy and that is local economic development.”
He said that while the Midwest saw a decline in manufacturing, there’s a regional “revival in jobs, innovation and investment” with wind and solar development. Solar installer and wind turbine technician are the No. 1 and 2 fastest growing jobs in the U.S., he pointed out.
“This has really fueled an American revival, in particular because of the resources in the Midwest. Regardless of what your politics is for the state, they all want that economic development and that investment. … If you just focus on climate change and the conflict around it, you miss a whole bunch of ways in which people are working together,” Danielson said.
Conservative circles are now forming their own clean energy groups, Danielson said. He also said Republicans deserve some credit for energy transitions, calling Sen. Chuck Grassley “the grandfather of wind” because he helped to create the production tax credit.
Daniel Lutat, director of sustainable energy resources and technologies for Iowa Lakes Community College, said his students look at wind generation as a bridge technology to discover “the next best idea” in utility-scale renewable energy.
“When you talk about the industry having just over 100,000 people supporting wind right now, that’s more than coal, nuclear and natural gas combined,” Lutat said, referencing the statistic that about 114,000 Americans have jobs in the wind industry.
Iowa Utility Association Executive Director Chaz Allen also appeared at the Iowa panel to recount his time as mayor of the city of Newton, as a Maytag manufacturing facility closed its doors in 2007. Newton, dubbed the “Washing Machine Capital of the World,” had been producing washers since 1893.
Newton has since then reinvented itself as a wind turbine blade producer.
“I’ve seen the impact it’s had on the community that was in dire need of employment. … I’ve become an energy person because of that,” Allen said.
He said sustainable targets from major companies like John Deere or Facebook are driving an appetite for renewable generation.
“In years past, it needed to be affordable and reliable. Now it needs to affordable, reliable, sustainable and renewable. Because everyone is expecting that they’re getting green energy,” Allen said.
Iowa Rural Development Council Executive Director Bill Menner also pointed to the impact of wind on the agricultural sector. He said he interviewed several farmers this year whose farms would have been in the red because of rising tariffs but were kept in the black by the guaranteed income from their wind turbine land leases.
The winds of change will continue to favor WEC Energy Group after a strong 2019 performance, the company indicated last week.
“In 2019, we benefited from additional capital investment, production tax credits and continued emphasis on cost control,” CFO Scott Lauber said during an earnings call Thursday that largely focused on the company’s growing investments in wind generation.
Executive Chairman Gale Klappa reported on the list of projects, including the 97-MW Coyote Ridge Wind Farm in South Dakota, which is now in service and “will contribute a full year of earnings in 2020,” he said, particularly from the project’s tax credits.
“We invested approximately $145 million for our 80% share of the wind farm, and we’re entitled to 99% of the tax benefits,” Klappa said. He also noted that the project has a 12-year offtake agreement with Google Energy for all energy produced.
Klappa pointed out that WEC also will acquire an 80% ownership interest in Invenergy’s Thunderhead Wind Energy Centre in Nebraska for $338 million. The 300-MW project is expected to be in service at the end of the year. Klappa said he expects it will qualify for PTCs, and it also comes with a “long-term” offtake agreement with AT&T for all its output.
WEC also expects to earn PTCs from its 80% ownership in Invenergy’s 250-MW Blooming Grove Wind Farm in Illinois for $345 million. Commercial operation is also expected by the end of 2020.
We Energies’ Glacier Hills Wind Park | WEC Energy Group
“Blooming Grove has a 12-year offtake agreement with affiliates of two multinational companies that are investment grade,” Klappa said. “Overall, we’re very encouraged about these investments in renewable energy, which will serve strong businesses for years to come. We expect the return on these investments to be higher than our regulated returns. Of course, we’re being very selective as we vet future projects. We’re only interested in projects that achieve our financial return metrics and do not change our risk profile.”
And a little sunshine was mixed in with the long list of wind topics.
WEC CEO Kevin Fletcher reported the utility has broken ground in Wisconsin on two solar projects for subsidiary Wisconsin Public Service: Two Creeks and Badger Hollow 1.
“Our share will total 200 MW with an expected investment of approximately $260 million. Both projects are scheduled to begin producing energy by the end of this year,” Fletcher said.
He also noted that subsidiary We Energies in August filed with the Wisconsin Public Service Commission to acquire 100 MW of capacity at the Badger Hollow II Solar Park for a $130 million investment. He said he expects the commission’s decision in spring.
Finally, Fletcher reported that in early 2019, the utility completed construction on two new natural gas-fired power plants in Michigan’s Upper Peninsula. The projects were “on time and on budget,” Fletcher said.
“These plants are now providing a cost-effective, long-term power supply for our customers in the Upper Peninsula. With these new units operating, we were able to retire our older, less efficient coal-fired plant at Prescott. This resulted in significant operations and maintenance savings and reduced CO2 emissions,” he said.
Xcel Energy last week reported year-end earnings of $1.372 billion ($2.64/share), up from 2018’s performance of $1.261 billion ($2.47/share) and marking the 15th straight year the company has met or exceeded its guidance.
Minneapolis-based Xcel attributed the positive results to favorable regulatory rulings in its utilities’ states. Colorado’s Public Utilities Commission verbally awarded Xcel a $41.5 million rate increase and a 9.3% return on equity, below its requests of $158 million and 10.2%. In December, Minnesota’s PUC approved a one-year deferment of Xcel’s three-year $465 million rate case.
“I would challenge anybody to find a utility that is more focused and has … 100% of their growth coming from regulated operations,” CEO Ben Fowke said during a conference call with analysts Thursday. “There’s nobody that’s more pure-play and vertically integrated than Xcel Energy, and that’s the way we mean to keep it.”
Transmission being built in Xcel subsidiary Southwestern Public Service’s territory | SPS
Fowke said Xcel’s operations and maintenance costs were down almost 1%, “even while making incremental investments in our system,” and noted three wind projects, representing almost 700 MW of capacity, were completed under budget. The company has another 2 GW of wind projects under construction, he said.
For the quarter, Xcel posted earnings of $292 million ($0.56/share), as compared to 2018’s final quarter earnings of $215 million ($0.42/share).
The company’s share price opened down at $67.10 on Thursday but finished the week at $69.19, after setting a new all-time high of $69.52 Friday morning.
SANTA FE, N.M. — SPP’s Board of Directors last week approved a transmission plan that will result in an estimated $545 million in projects over the next six years.
The 2020 SPP Transmission Expansion Plan (STEP) report, a comprehensive list of transmission projects in the RTO’s footprint over a 20-year horizon, lists 78 primarily substation upgrade projects as being approved for construction. Another 16 notifications-to-construct, valued at a projected $88.7 million, were withdrawn.
Newly appointed COO Lanny Nickell said during the board’s Jan. 28 meeting that the STEP represents the least amount of transmission investment since 2008. It includes two 345-kV projects that will be competitively bid through SPP’s transmission owner selection process: a $77 million, 60-mile line near Tulsa, Okla., and a $152 million, 105-mile line and terminal equipment in Kansas and Missouri.
The RTO has already issued a request for proposals for the Oklahoma project and expects a board decision in October. The latter project terminates in Associated Electric Cooperative Inc.’s service territory and will require a cost-and-usage agreement to first be filed at FERC.
SPP member companies last year completed 39 system upgrades in eight states at an estimated cost of $190.4 million, the report said.
The expansion plan was approved as part of a consent agenda that included a number of mostly minor revisions to SPP’s bylaws, one of which codified the board chair’s role as chair of the Strategic Planning Committee.
The package also included a revision request (RR389) that provides a testing exception for derated generating units that were out of service or derated because of a forced outage during the preceding peak season, allowing them to satisfy an operational test requirement after repairs are complete.
WEIS Tariff Approved, on to FERC
Directors approved a standalone Tariff and related governance documents for the Western Energy Imbalance Service (WEIS) market, scheduled to begin operations on Feb. 1, 2021.
The approval clears the way for SPP to file the Tariff for FERC’s approval, along with a Western joint dispatch agreement (WJDA) and a charter for the Western Markets Executive Committee. The WJDA is the contractual arrangement between SPP and WEIS participants that governs the RTO’s obligations to administer the market and its compensation for running the market.
Members Committee representatives from Dogwood Energy, Evergy, Nebraska Public Power District, Oklahoma Gas & Electric, Oklahoma Municipal Power Authority, Public Service Company of Oklahoma and Southwest Public Service abstained from their advisory vote over concerns that members did not have enough transparency into the market’s development.
Board Chair Larry Altenbaumer sought to assuage members’ concerns that Western activities were being kept from them.
“We want to ensure that we are very robust in our communications with the members and are transparent in terms of our process,” he said. “We’re committed to making sure everyone is well informed.”
The WEIS Tariff is based on the Energy Imbalance Service market SPP operated in the Eastern Interconnection from 2007 to 2014. It will provide guidance for customers to become participants, convey how they will communicate with the RTO, and outline how the market will be settled and billed.
Seven Western Interconnection utilities have signed up to participate in the five-minute, real-time balancing market, which will be offered as a contract service. (See SPP Board OKs $9.5M to Build Western EIS Market.)
SPP’s Market Monitoring Unit will provide market oversight. In a memo filed with the board’s meeting materials, MMU Executive Director Keith Collins said the Monitor “fully supports” the WEIS and the expansion of electricity markets, but he also listed his concerns over market liquidity, settlements and market power.
Collins said the proposed Tariff language does not address the “potential negative” effect on the market when minimum load requirements are not met, and he noted that SPP is not currently working on protocol language to address the MMU’s market-liquidity concerns.
The MMU has begun a study to determine what mitigation measures may be necessary to ensure market efficiency in the WEIS, Collins wrote.
Brown Delivers Optimistic Final Report
Outgoing CEO Nick Brown joked he had prepared a two-hour sermon for his last report to the board but put it off until his final appearance before the board during April’s round of governance meetings.
“Now is not about the past. I’m tremendously excited about the position this company is in,” Brown said. He listed the addition of new directors bringing “fresh perspective and fresh passion and fresh accountability to our governance” and SPP’s incoming leaders as having successfully placed the organization to take on future challenges.
Brown said the RTO is “firmly, firmly positioned” to implement the Holistic Integrated Tariff Team’s recommendations and to develop a new strategic plan.
“Our current plan is nearing four years in age,” he said. “I think it’s going to be a tremendous time for me to observe all of the efforts this organization is going to undertake over the next year. I leave this meeting with a full heart about the position SPP is in to move forward. I look forward to April and your opportunity to listen to my two-hour sermon.”
Oversight Committee Chair Joshua Martin III reported that SPP once again received an “unqualified opinion” following its latest system and organization controls 1 audit, its 10th such opinion in a row.
Danly Re-nomination Could be Months Away
Patrick Clarey, FERC’s liaison to SPP and MISO, said that James Danly’s nomination to the commission will likely be sent back to the Senate within the next couple of months.
Danly, FERC’s general counsel, was nominated last year to fill the vacancy left by Kevin McIntyre’s death. However, the Senate failed to act on his nomination before the session ended last year. According to Senate rules, the White House must once again send Danly’s nomination to Capitol Hill during a regular session.
Since then, Commissioner Bernard McNamee said he would not seek another term when his current term expires June 30, though he said he would not leave until a replacement is confirmed to his seat. (See McNamee Declines to Seek Reappointment.)
Google Loving RTOs
Jeff Riles, Google Energy’s global energy policy and markets lead, said during a presentation to members that his mammoth company “loves” RTOs and ISOs. Google, already SPP’s largest corporate buyer with 1,135 MW of purchase power agreements, only joined SPP last year. (See Google Searches, Finds Membership in SPP.)
“Quite honestly, we wish they were in every corner of the country,” he said. “There are critical policy questions in front of you, but we think power markets are absolutely essential to achieve our corporate objectives.”
MISO tossed a curveball at stakeholders Tuesday when it said it will now consider two types of solutions to mitigate its Midwest-South transmission constraint before the original term of the settlement agreement facilitating transfers draws to a close.
The 2016 agreement with seven joint parties — including SPP — limits transfers between MISO Midwest and South to 3,000 MW southbound and 2,500 MW northbound. The deal is set to expire next year, leaving MISO and its members to confront escalating costs under a new arrangement.
Speaking during a conference call Tuesday, economic studies engineer David Severson revealed more details about the original solution, saying that MISO is focusing on three proposed projects to alleviate the constraint.
But Severson also posed a new option: MISO could avoid building new transmission by instead exploring ways to purchase firm capacity to supplant the settlement agreement. The revelation caused consternation among some members on the call.
Joint parties to the settlement agreement | MISO
Three Projects…
Severson explained that each of three proposed projects under consideration would create a new 345-kV line terminating at the Jim Hill substation in southeastern Missouri. Costs for the proposals range from $152 million to $262 million, with cost-benefit ratios from 2.04:1 to 1.1:1. Two of the projects would increase the existing 1,000-MW contract path by 2,574 MW, while the most expensive proposal would increase it by 2,302 MW.
MISO requires projects to demonstrate at least a 1:1 benefit-to-cost ratio over 20 years to be considered under its Market Congestion Planning Study. It used an economic model from its 2019 Transmission Expansion Plan (MTEP 19) to estimate benefits for the proposals.
“Going forward, we plan on doing some refinement, getting stakeholder feedback and doing some external outreach,” Severson said of the project ideas.
MISO had been focusing on nine possible projects after receiving 35 proposals last summer to alleviate traffic on the constraint or even eliminate the need for the settlement agreement altogether.
RTO staff extended its analysis of the projects beyond the MTEP 19 approval deadline in December. (See MISO Studying Projects to Cut North-South Tx Reliance.) That work will be completed in the first half of this year, MISO executives have said.
During Tuesday’s call, MISO staff said the three projects will now enter a more rigorous testing that includes alternative components. WPPI Energy’s Steve Leovy said MISO should examine combining elements of the three different projects.
Some MISO stakeholders warned that approval of just one of the projects might not be a panacea for all subregional transfer constraints. They called for more analysis on the nearby system.
Veriquest Energy’s David Harlan asked MISO to take a closer look at how the projects could alter flow patterns on nearby lines or tax existing substations, impacting either SPP or the joint parties to the settlement agreement.
“I would hate to see us lose all of our settlement payments … only to hit a constraint with SPP,” WEC Energy Group’s Chris Plante added.
The agreement requires MISO to make monthly payments for usage based on a capacity factor. At a 20% or less capacity factor, MISO pays $1.33 million per month, while a 20 to 70% capacity factor sends the price to $2.25 million per month. A factor higher than 70% results in a $3.17 million monthly payment.
Those payments are set to escalate annually beginning next month — by an additional 2% for up to a 70% capacity factor and 4% for capacity factors above 70%.
The agreement’s initial term ends on Jan. 31, 2021, when it automatically converts into yearly extensions which can be terminated with a 12-month written notice by any of the settlement’s seven joint parties, which include MISO, SPP, Tennessee Valley Authority, Southern Co., LG&E and KU Energy, Power South Energy Cooperative and Associated Electric Cooperative Inc. If that happens, the parties enter a four-month renegotiation period. If no agreement can be reached, MISO’s rights on the transmission systems of the other parties are terminated, leaving it once again subject to paying SPP unreserved transmission-use penalties for flows above MISO’s 1,000-MW contract path capacity.
Senior Adviser Jack Dannis said MISO is currently discussing next steps of the settlement agreement with the other parties.
…or Buy Firm Service?
Dannis emphasized that MISO has three options for increasing its contract path post-settlement agreement: building new transmission, adding a new transmission-owning member that connects the regions, or obtaining firm transmission service from another company connected to both regions.
“We’re in frequent communication with SPP and the joint parties,” Dannis said. The parties are currently “performing transmission planning analyses to identify cost-effective solutions for providing MISO firm transmission rights,” he said. Those solutions may involve upgrades to SPP or neighboring systems in order to offer MISO new firm rights.
Dannis said for every 1 MW of increased capacity on the contract path, MISO’s payment is reduced by $667/MW-month.
That MISO is considering purchasing firm transmission rights from its neighbors came as a surprise to some stakeholders.
LS Power’s Pat Hayes said MISO last year only asked that transmission developers propose solutions that could increase capacity on the transfer limit — and didn’t let on that firm service purchases were also an option under consideration.
“This is a pretty big transparency issue, and we should be able to participate, and we’re not right now,” Hayes said. “I know that there are other parties in the room that feel this way.”
Hayes said it also isn’t clear whether MISO stakeholders would have another opportunity to propose projects that would increase transfer capacity between the regions through a coordinated system plan between MISO and SPP. The RTOs will decide this spring whether to embark on a study that could result in an interregional project. MISO officials said it was too early to speculate on what type of projects would be examined under such a study.
SPP continues to add fresh blood to its leadership ranks, announcing on Thursday that two new officers will join its senior leadership team from within the RTO’s ranks.
Sam Ellis | SPP
The grid operator said its Board of Directors had elected Sam Ellis as chief information security officer and vice president of information technology, and Antoine Lucas to serve as the organization’s vice president of engineering, effective Feb. 1. The two were recommended by CEO-elect Barbara Sugg and COO Lanny Nickell, SPP said, filling the positions left vacant by their earlier promotions. (See SPP Names Nickell COO, Adds Board Member.)
“Some of SPP’s greatest opportunities for advancement will depend on our ability to build and manage relationships with our stakeholders and to innovate,” Sugg said in a statement. “Both Sam and Antoine are exactly the kind of people we need leading us into the future.”
Ellis, the organization’s director of cybersecurity and controls, will assume oversight of the IT department from Sugg. He will be responsible for technology development and deployment, monitoring, support and cybersecurity for SPP and its members, and for establishing IT strategy and policies. Ellis joined the RTO in 2003 from Empire District Electric and has 26 years of industry experience in transmission and generation operations and electricity and natural gas trading.
Lucas, formerly director of transmission planning, replaces Nickell and will oversee the transmission expansion plan’s ongoing development, tracking expansion projects, administering generator interconnection processes, engineering studies and supporting SPP’s real-time operations functions. He joined the organization in 2007 after five years with Entergy Services as an engineer and system operator.
Both Ellis and Lucas have played prominent roles recently in front of stakeholders. Ellis was program director of the day-ahead market’s successful implementation in 2014, while Lucas has served as the point person for SPP’s Integrated Transmission Planning process.
MISO’s first storage-as-transmission proposal has drawn several protests from stakeholders who say the plan gives transmission owners an unfair advantage in developing the resources.
Multiple entities said the ruleset, filed with FERC on Dec. 12, is geared to providing incumbent TOs an effective monopoly on storage assets functioning as transmission, harming competition. Several urged FERC to reject the filing (ER20-588).
The proposal limits storage-as-transmission assets to transmission-only functions operated by TOs. As such, MISO labeled these resources storage-as-transmission-only assets (SATOA), and they would be barred from simultaneous participation in its energy markets — for now. (See Despite Pushback, MISO Pursuing TO-only SATA.) The RTO has said its 802-page plan will avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services.
MISO’s 2019 Transmission Expansion Plan (MTEP 19) includes just one SATOA project proposed for Wisconsin, but the RTO doesn’t have a cost-recovery mechanism for such assets. (See MTEP 19 Could Yield First MISO SATA Project.) Its Board of Directors is slated to hold a special vote on approval of the project once FERC gives the go-ahead on the rules, including cost recovery.
Invenergy’s Grand Ridge Battery Storage Facility in Illinois | BYD
In comments filed with FERC, LSP Transmission Holdings said the proposal “as presented would effectively create a storage project monopoly for MISO’s incumbent transmission owners, just as this promising technology is in its infancy.”
A group of nearly 20 entities — including environmental nonprofits, consumer groups and utilities such as DTE Energy — said the ruleset was unlawful because it creates unduly discriminatory preference for MISO’s TOs.
The group also said the plan ignores FERC’s requirement that RTOs remove barriers to the participation of electric storage resources, arguing that Order 841 and MISO’s SATOA definition cannot be considered in isolation. It also contends that MISO’s Planning Advisory Committee originally wanted non-TOs and TOs alike to propose and construct SATOA, but that MISO ultimately favored the wishes of the latter.
“MISO’s decision to ignore the PAC’s recommendation in favor of the SATOA proposal demonstrates a lack of independence from the will of its TO members,” the groups wrote.
DTE representatives had promised to protest the filing during December’s board meeting, where directors voted unanimously to approve MTEP 19, which contains American Transmission Co.’s Waupaca area energy storage project meant to ease transmission reliability issues in central Wisconsin. In stakeholder meetings, DTE has repeatedly said the TO-only provision amounts to preferential treatment because generation owners cannot operate SATOA.
Not ‘Comparable’
MISO officials have said storage developers and owners who are not classified as TOs could still propose projects under existing rules on selecting non-transmission alternatives (NTAs) in the place of transmission projects. The RTO last year placed several mentions of storage resources into BPM 20, the business practices manual managing NTAs.
But storage owners and developers said the treatment remains unequal because NTAs must first clear MISO’s approximately three-year generation interconnection queue, which is not a requirement for TOs proposing SATOA, who instead submit their projects for study through the annual MTEP process.
Invenergy Storage Development complained the NTA option doesn’t offer “comparable opportunities.”
“Unlike SATOA, companies proposing NTA projects must first proceed through the multiyear generator interconnection queue, and unlike SATOA, those projects would be required to pay transmission charges with respect to the delivery of energy when the storage facility is charging from the MISO transmission grid. As a result, even though an NTA might present the very same storage solution as a SATOA, it cannot effectively compete against a SATOA, and transmission owners will maintain a monopoly on owning storage projects serving as a transmission asset,” Invenergy said in its protest.
Invenergy added that MISO’s proposed ruleset “ignores the fact that any expertise that transmission owners are assumed to have as to their respective transmission systems or in developing and owning traditional transmission, is inapplicable to SATOA — it is developers, like Invenergy, that have the relevant experience in owning and operating storage projects.”
The Michigan Public Service Commission said it was similarly “compelled” to oppose the filing because MISO isn’t proposing equal treatment for TOs’ and non-TOs’ storage projects. “No storage project should have an unfair advantage over any other project. Since the SATOA proposal discriminates against non-TO storage projects in favor of TO projects, the MPSC urges the commission to reject the proposal and direct MISO to collaborate with interested stakeholders to prepare a truly nondiscriminatory proposal,” it said.
Storage developer GlidePath said MISO’s proposal “completely misses the mark” and called it a “rushed solution.” Instead of “encouraging the development of single-use storage devices limited only to supporting the transmission system,” GlidePath said the RTO should create a more comprehensive compensation mechanism for storage resources and other generators that can support the transmission system.
GlidePath also said there are “clear competitive concerns inherent in permitting” SATOA to circumvent MISO’s interconnection process.
MISO Director of Planning Jeff Webb has predicted that the RTO will early this year begin addressing the issue of allowing storage functioning as transmission to simultaneously function in the energy market.
FERC on Wednesday accepted NERC Notices of Penalty against the Bonneville Power Administration, Idaho Power and the Niles Light Department. There were no monetary penalties.
The commission said it would not review NP20-5 regarding BPA or NP20-6, a spreadsheet NOP. The spreadsheet included 16 critical infrastructure protection (CIP) violations against unnamed entities reported by the Western Electricity Coordinating Council and ReliabilityFirst, which were redacted to protect sensitive information about how the entities implemented controls to address security risks. Five of the violations included financial penalties totaling $525,000.
Bonneville Power Administration
BPA was cited for two incidents, the first in September 2015, when it discovered that the rating on one of its current transformers (CT) was lower than the facility ratings of two associated transmission lines. The CT should have been rated as the most limiting element when BPA established the facility ratings. However, the utility’s rating methodology assumed CT equipment “to be sized such that it would never be the most limiting element in a facility.”
According to a NOP filed Dec. 30, after BPA reported the discovery to WECC, the regional entity performed an analysis that revealed similar issues in at least 52 facilities, at least six of which were part of one or more of WECC’s major transfer paths (NP20-5). The widespread failure to effectively determine facility ratings violated the FAC-009-1 standard. Although WECC found that the violation “posed a serious risk to the reliability of the bulk power system,” BPA is not subject to monetary penalties, in accordance with a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal governmental entities.
The RE noted that the incident constituted BPA’s first violation of the standard in question; BPA self-reported the violation and cooperated during the enforcement action; there was no evidence of any attempt to conceal the violation or intent to do so; and the violation did not cause or extend a loss of load. BPA typically operates its system conservatively, and the affected facilities were never in danger of exceeding a system operating limit.
Workers upgraded the Bonneville Power Administration’s Pacific Direct Current Intertie in 2016. | Bonneville Power Administration
In addition, BPA has since implemented a mitigation plan approved by WECC to prevent future incidents. In a separate incident, BPA submitted a self-report in May 2017 saying it may have failed to comply with six transmission operator (TOP) and interconnection reliability operations and coordination (IRO) requirements resulting from an outage on Nov. 30, 2016. BPA implemented the outage as part of its boundary remedial action scheme (RAS), which includes line-loss logic for three transmission lines.
BPA did not correctly implement the study limit information memo (SLIM) required by its operating plan, which specified that a 650-MW system operating limit (SOL) should be set at the one boundary’s flowgate.
Although a dispatcher limited output of the main generating station on the lines to 650 MW, BPA did not lower the boundary SOL from 1,300 MW to 650 MW.
Because the lower SOL was not entered in the control system, the alarm monitoring did not alert to three SOL exceedances between 2:15 and 2:45 p.m.
WECC said the incident, which posed a “moderate” risk, resulted because the dispatcher mistakenly relied on a dispatch standing order rather than the SLIM.
“BPA was already operating its system with the RAS in a degraded state. If BPA were to have lost another line, the RAS could have caused a loss of load and potentially opened the remaining lines entirely,” WECC said.
It credited BPA for discovering the mistake during a routine monitoring activity nine days after the incident and said the 650-MW limit on the generating station reduced the risk.
Idaho Power
Idaho Power submitted a self-report on July 24, 2018, saying it may have failed to comply with PRC-005-2(i) R3 by failing to maintain a battery used to power communications equipment during an emergency outage at a 230-kV substation for two 18-month intervals.
The vented lead acid battery was maintained in June 2014, but the company missed its 18-month maintenance interval on Jan. 1, 2016, and did not correct the error until July 2017.
WECC said the problem resulted when a transmission and distribution engineer disabled the battery maintenance trigger because he thought the utility’s communications group was responsible for tracking the maintenance and testing. The communications group had not been notified of the change in responsibility, the RE said.
The violation posed a minimal risk because the battery voltage was continuously monitored by the energy management system, which would have produced an alarm had a battery failure occurred.
WECC said the company’s PRC-005 compliance history was an aggravating factor in the incident but imposed no monetary penalty.
Niles Light Department
During a compliance audit in spring 2018, ReliabilityFirst determined that the Niles Light Department, the distribution provider for the Ohio city, had violated COM-002-4 R3 by failing to conduct initial training for each of its operating personnel who can receive oral two‐party operating instructions.
The city did not train three individuals until March 1, 2018, although they had been receiving operating instructions from FirstEnergy before then. The training requirement was effective July 1, 2016.
The risk of harm to the grid was partially reduced because Niles’ personnel only receive operating instructions in the presence of FirstEnergy operators with written switching orders. “Although entity personnel had not been formally trained on how to receive an oral two‐party, person‐to‐person operating instruction, the entity indicated that personnel performed three-part communication in practice when receiving operating instructions,” ReliabilityFirst said.
Niles misinterpreted the standard, believing that its established communication process with FirstEnergy meant it did not need to train its own personnel.
The audit also found Niles in violation of PRC-005-2(i) R3 for failing to conduct all required testing for a battery and charger. Niles failed to perform an unintentional ground test (required every four months); a battery terminal connection resistance test (required every 18 months); a battery intercell or unit-to-unit connections resistance test (18 months); and load tests (every 18 months and every six years).
RF said Niles failed to update its protection system maintenance program with the new tests as required.
“The risk is partially reduced because the entity was performing quarterly tests and monthly tests on the protection system equipment and that testing would likely indicate to the entity any battery degradation before failure occurred,” RF said, noting the city’s peak load is only 68 MW.
