Vistra Energy said Monday it closed its acquisition of Dynegy following a FERC order concluding the $1.7 billion deal raised no competitive concerns (EC18-23).
The all-stock deal will create a power generation and retail giant owning 40 GW of capacity and serving nearly 3 million customers, mainly in ERCOT, PJM and ISO-NE. FERC’s April 4 approval was the last regulatory step required to complete the deal, which had already been cleared by regulators in New York and Texas.
| Vistra Energy
Dynegy’s combined cycle gas turbine fleet and geographically diverse portfolio were a big attraction for Vistra, which owns 18,000 MW of generation capacity in ERCOT. Dynegy’s 27,000 MW will give it the following market shares in these organized markets:
CAISO: 2.96% (2.16% after accounting for capacity under long-term contracts).
ISO-NE: 12.1% (Rest of Pool zone); 11% (Northern New England zone).
FERC has no jurisdiction over the combined company’s generation in ERCOT. The Public Utility Commission of Texas declined a staff recommendation that it require Luminant, Vistra’s generation arm, to divest itself of at least 1,281 MW of capacity to keep the post-merger Vistra below the statutory cap of 20% of ERCOT installed capacity. (See Texas PUC Conditionally Approves Vistra-Dynegy Merger.)
FERC rejected a protest by Public Citizen, which argued that the applicants’ horizontal competitive analysis should have included generation owned by Dynegy’s major shareholder, Energy Capital Partners. Public Citizen noted that ECP is seeking to acquire Calpine.
| Vistra Energy
But the commission ruled ECP’s generation did not have to be included in the analysis after its action in January to reduce its stake in Dynegy from 14.88% to 9.9%, below the 10% threshold that imputes control. ECP’s post-transaction ownership of the combined Vistra entity will be 1.7%, FERC said. “As such, under the commission’s regulations, Dynegy will not be affiliated with ECP, nor under its control,” FERC said.
The commission also said the Dynegy acquisition would not have an impact on vertical competition, saying the only transmission facilities controlled by the applicants in commission-jurisdictional markets aside from generator interconnections are Smoky Mountain Transmission — 86 miles of transmission connected to the Duke Energy Carolinas and Tennessee Valley Authority systems — and Electric Energy, six 8-mile-long parallel generation tie lines. Both provide service under commission-approved open access tariffs.
In related orders Thursday, FERC also set hearing and settlement procedures to review the reasonableness of the reactive service rates for Dynegy’s Illinois Power (ER16-233-001, EL18-133) and 15 other subsidiaries (ER15-1641, et al.).
Vistra CEO Curt Morgan’s executive team, including Chief Operating Officer Jim Burke and Chief Financial Officer Bill Holden, will lead the combined company, based at Vistra’s headquarters in Irving, Texas. The new board is expected to have 11 directors: the current eight members of the Vistra board and three members from Dynegy’s board.
MISO on Tuesday began using Wisconsin transmission to deliver electricity to Michigan’s Upper Peninsula after the failure of two of American Transmission Co.’s submarine cables in the Straits of Mackinaw.
The situation is not disrupting the RTO’s grid reliability, and there is adequate Wisconsin transmission capacity to offset the outage, according to MISO spokesperson Mark Adrian Brown.
“MISO continues to work closely with ATC to maintain electric reliability in the Upper Peninsula. Power to serve the Upper Peninsula of Michigan continues to be routed through Wisconsin, as is the normal flow of power into the Upper Peninsula, and there is ample transmission via the alternative route,” Brown told RTO Insider in an email.
ATC has said it does not know how long the outage will last. MISO may seek to reschedule future planned outages to ensure continued reliability depending on the duration, Brown said.
The company on Tuesday said it took the “unprecedented step” of shutting down two damaged underwater transmission lines that connect lower Michigan with the Upper Peninsula. The pair of 4-mile circuits were leaking a toxic, petroleum-based fluid used for insulation into the lake, and that “extreme weather conditions, including icing in the channel and on shore” prevented an investigation of the damage, according to the company.
ATC said the cables initially tripped offline about 30 seconds apart on April 1, although aerial patrols showed no visible damage to the overhead parts of the system. One of the cables was constructed in 1975, the other in 1990. According to the U.S. Coast Guard, about 600 gallons of hazardous petrochemical fluid leaked into the water.
The company has not established the cause of the damage and said the lines “cannot be repaired and have been rendered permanently inoperable.” The company said it will be checking on the condition of the other four cables it operates in the straits once weather permits. Upper Michigan this week experienced heavy snow and gusty winds.
ATC spokesperson Jackie Olson on Thursday said the company is testing the remaining cables to determine if they can be reconfigured to restore one of the circuits to operability.
“Our investigation as to the cause is ongoing; however, the weather conditions are such that we cannot get a remote submarine vehicle in to do an inspection any time soon,” Olson said.
“It was an extraordinary set of circumstances, but ultimately, the decision to shut down the cables had to be made,” said ATC Chief Operating Officer Mark Davis. “We will continue to investigate the cause of the incident, determine any necessary remediation efforts and continue communicating with the appropriate regulatory agencies.”
ATC said it is coordinating with MISO and Midwest Reliability Organization “to determine short-term and long-term solutions.” The company said it has notified multiple agencies of its decision to shut down the electrical cables, including EPA, the National Oceanic and Atmospheric Administration, the Coast Guard, U.S. Fish and Wildlife Service, Michigan Department of Environmental Quality, Michigan Department of Natural Resources and the Michigan Public Service Commission.
The Coast Guard on Wednesday said it established a unified command comprised of MDEQ members, county emergency managers, local native tribes, NOAA, FWS, EPA and ATC “to oversee the pollution response and mitigate any risks to the environment.” The Coast Guard said the maximum potential for the spill is more than 4,000 gallons, though ATC took pressure off the lines and fluid was not leaking as of April 4. The toxic risk to wildlife and drinking water is low, the Coast Guard said.
Having cracked wind penetration levels of 50% and 60%, SPP has now set its sights on the once unimaginable 70% barrier.
The RTO’s latest record came early on March 31, when wind energy accounted for almost 14.5 GW, or 62.13%, of its 23.3-GW total load at 1:54 a.m. SPP said it also set a new renewable penetration record of about 64.7% at the same time.
Spokesman Derek Wingfield told RTO Insider it’s difficult to predict how high SPP’s wind penetration levels can go, but staff have studied the effects of 70% levels. He said the RTO had forecast 70% penetration in late 2017, but transmission outages wound up limiting wind energy that day.
“It could be a possibility again this spring as load reaches minimum levels,” Wingfield said.
It was one of five wind penetration records set during the month, and the sixth of the year.
In February 2017, SPP became the first North American RTO to exceed wind penetration levels of greater than 50%. Its all-time high for wind generation came in December, when the system generated almost 15.7 GW of power from wind farms.
“The records are an indicator of the evolution of our system, and wind continues to be added to it,” Wingfield said. “Reliability and economics drive our market, and we’re proud that we’re able to reliably manage so much wind and provide some of the least-cost electricity in the country, based on the resources available to us.”
| Oklahoma Municipal Power Authority
The RTO has 17.75 GW of installed wind, much of it in Kansas, Nebraska, Oklahoma and West Texas. Another 5.3 GW of wind capacity has interconnection agreements but is not yet in service, and 35 GW of wind capacity is under various stages of review in the generator interconnection queue.
CARMEL, Ind. — MISO says it will likely go above and beyond complying with FERC Order 841, as it expands its market rules for storage after its initial filing with the commission later this year.
MISO Market Design Manager Kevin Vannoy said the RTO will soon begin presenting stakeholders with straw proposals for Order 841 compliance, but it intends to keep going after submitting a final proposal. MISO will continue to study the operational characteristics of energy storage to make a more comprehensive, but still unidentified, set of market rules in 2019 and 2020.
“We’re not going to just stop at Order 841 compliance,” Vannoy promised stakeholders during an April 4 Energy Storage Task Force meeting.
FERC last month granted MISO permission to create a Stored Energy Resource Type II to facilitate market participation, although it said the new definition needs more work that can be deferred into the RTO’s Order 841 compliance filing due in early December. (See FERC OKs MISO Plan to Expand Storage.) Vannoy said revising the resource type definition will get MISO “part way, but not all the way there” to compliance.
He added that MISO’s list of improvement projects, the Market Roadmap, includes a more comprehensive storage participation plan, although it didn’t place in the top eight priorities this year despite stakeholders giving it top ranking. (See 8 Projects Set for 2018 MISO Market Roadmap.)
MISO Director of Policy Studies J.T. Smith reported the RTO is meanwhile beginning to study how storage resources could be considered for economic transmission projects.
“There are still a lot of questions out there but not a lot of firm answers,” Smith said.
NEW BRITAIN, Conn. — Utility representatives and other stakeholders shared their views on evolving cost drivers, changing customer demand and new technologies at the Connecticut Public Utilities Regulatory Authority’s first-ever technical conference on grid modernization on Tuesday (17-12-03).
“We need to have technologies in place that understand how the system is operating in real time, with power coming from any direction on the system,” said Chuck Eves, director of engineering and strategic planning at Avangrid subsidiary United Illuminating (UIL).
Eversource Energy filed comments ahead of the conference calling for “foundational investments in sensing and monitoring communications, analytics, automation and control solutions.”
Jennifer Schilling, Eversource’s director of grid modernization, said her company breaks down its investments “into peak load, new customer growth, reliability and ageing infrastructure, and basic business, which includes capital repairs.”
The new opportunities arising from the growth in distributed energy resources are “adding a new dimension in our planning process,” which is why the company supported the timing of the technical conference, Schilling said.
“The nature of the changes in demand and the forecasting will be important in terms of thinking about what do we need to do differently to be able to say, ‘OK, if I have these categories of investment, how are they likely to change in the future?’” Schilling said.
Using Data
Connecticut Green Bank Associate Director Anthony Clark said his organization’s current investments are following and helping to boost customer demand, “but they are not following grid demand much at all. We just don’t have that insight.”
Clark thanked PURA, the state’s Department of Energy and Environmental Protection and UIL for helping the Green Bank start “really digging into this process on the grid side” through clean energy pilot programs.
“In much of the discussion here we’ve talked about the challenge of having solar PV or other resources where there isn’t sufficient data or resolution into the resource or ability to control it,” Clark said. “The technologies themselves are becoming smarter, so we’re looking at deploying smart inverters that will actually sense grid conditions and respond to them.”
Christian Bilcheck, vice president for smart grids innovation at Avangrid, said it’s important to think of DER in the aggregate, not as individual elements.
The utility is not necessarily going to have the answers to a lot of questions in the early days, he said.
“I can picture a data request coming in and it will look like we’re not sharing information, but we don’t have DER adoption modeling forecasts for circuits and substations right now,” Bilcheck said.
“It gets complicated, but I think if we keep approaching it from a practical perspective, we’ll get there,” he said. “Not just the data needs, but I think the goal of the data is to help inform the types of investments that we should be looking forward to, how DERs can play a role in that frame and even help shape policy.”
Lauren Savidge, DEEP director of energy supply, said the agency is learning from what other states are doing with DER, citing a recent Michigan Public Service Commission solar program report “that was pretty thorough on compensation for solar, how different customers in their territory use solar.”
Cost and Sustainability
PURA Chair Katie Dykes said, “The cost-effectiveness testing will help us learn a lot about — particularly from the utilities’ perspective — what the grid currently can do and where the limitations are.”
Eves said it’s important to consider the long-term sustainability of solutions “as we evaluate the lifecycle costs of the choices we make, to sustain those into the future, five, 10, 20, 40 years down the road.”
In its comments, the Acadia Center said that any calculation of cost-effectiveness should be aligned with the state’s consumer, energy and environmental goals.
“Cost-benefit frameworks should be designed or expanded to fully reflect priorities such as reducing energy bills and reducing consumers’ energy burden, addressing climate change, enhancing consumer control and choice, and systemwide efficiency,” Acadia said.
PURA Commissioner Michael Caron returned the conversation to what Connecticut can learn from other jurisdictions.
“In California and Hawaii, they are blazing the trail ahead of us from the perspective of penetration and how they’re dealing with those issues, so there’s a lot to learn from what’s occurred in those states … learning from their mistakes as well as from their successes,” Eves said.
PURA is seeking written follow-up comments on the technical conference by April 10 and will later this month issue a final notice of scope of procedure for its exploration into the issues of grid modernization. The agency plans to begin discovery in the coming months and form working groups by this summer before soliciting reports from them in the fall.
FERC said yesterday that a preliminary investigation indicates that Public Service Enterprise Group committed multiple violations of PJM market-bidding rules and made “false and misleading statements” to RTO staff, stemming from issues PSEG says it self-reported in 2014 and has since set aside $35 million to address.
The Notice of Alleged Violations charged PSEG Energy Resources & Trade, which markets the output of PSEG Power’s generation fleet, with violating both PJM’s Tariff and FERC regulations. PSEG’s trading arm submitted incorrect cost-based bids into PJM’s daily energy market from as early as 2005 through 2014 and lied to PJM regarding costs associated with certain units, commission staff alleged.
The notice also said the determinations were preliminary and provided few additional details about the confidential investigation. It did not indicate when or whether any definitive action would be taken against PSEG.
PSEG’s Sewaren 7 natural gas generator is expected to go into operation in summer 2018. | PSEG
PSEG Power reported in May 2014 through PSEG’s first-quarter financial results that it had “discovered that it incorrectly calculated certain components of its cost-based bids for certain generating units in the PJM energy market, with resulting over-collection of revenues related to its fossil fleet.” It said the issue had been reported to FERC, PJM and PJM’s Independent Market Monitor, Monitoring Analytics, and recorded a $25 million charge to its income to account for potential financial repercussions.
In PSEG’s 2014 second-quarter results, PSEG Power announced that a subsequent internal investigation performed by outside counsel found “additional pricing errors in the cost-based bids” and “that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amounts for which Power was compensated in the capacity market for those units.”
The company said it corrected the errors and revised processes “to ensure that the pricing errors identified in the calculations of the bids and differences in quantities offered into the energy market from those in the capacity market have been corrected” and “to help mitigate the risk of similar issues occurring in the future.” It said it doesn’t have access to PJM data “to determine if the differences in quantity had any impact, and if so, the level of that impact.”
FERC in September 2014 opened its investigation into PSEG’s fossil-fuel fleet in New Jersey, which includes the 1,229-MW Bergen combined cycle gas turbine, 1,566-MW Linden CCGT, 81-MW Essex simple cycle gas combustion turbine, 168-MW Burlington CT and the Sewaren facility, which was a 445-MW gas-fired plant at the time but was damaged during Hurricane Sandy in 2012 and is being rebuilt as a 540-MW CCGT. It also includes the 456-MW Kearny CT, but that unit wasn’t brought online until 2012.
In its 2017 10K report filed with the Securities and Exchange Commission, PSEG said it “believes the disgorgement and interest costs related to the cost-based bidding matter may range between approximately $35 million and $135 million, depending on the legal interpretation of the principles under the PJM Tariff, plus penalties.” It has accounted for the low end of that estimate “since no point within this range is more likely than any other.”
“Power continues to believe that it has legal defenses that it may assert in a judicial challenge, including the legal defense that its cost-based bidding in a substantial majority of the hours was below the allowed rate under the Tariff and therefore any errors in those hours did not violate the Tariff or were immaterial,” PSEG said in the filing. “Furthermore, it is unclear whether the quantity of energy offered violated any legal requirement.”
In an email to RTO Insider, PSEG spokesman Michael Jennings confirmed the company has set aside $35 million over the issue, adding that “we are not discussing the particulars.” Representatives for PJM and Monitoring Analytics confirmed that they could not discuss details of the investigation.
PSEG says its trading arm, based at its corporate headquarters in Newark, N.J., is “among the nation’s first and most successful energy trading organizations.” In addition to marketing PSEG Power’s output, it acquires and hedges fuel and power, dispatches plants, manages gas supply and trades energy-related products.
Generation developers and transmission providers on Wednesday called for more direction from FERC to improve coordination of “affected system” studies in the generation interconnection process.
Suggested improvements on the second day of a FERC technical conference included sharing study models earlier, clear timelines and cost estimates, and better definitions for identifying an affected system — one impacted by new generation in a neighboring region (EL18-26, AD18-8). (See related story, Renewable Gens Face Off with RTOs at Seams Tech Conference.)
Day 2 focused largely on the commission’s generator interconnection Notice of Proposed Rulemaking (RM17-8). The NOPR noted that because affected systems are not bound by the practices of the system processing an interconnection request, its process and schedule may differ from the host.
“The challenge with California is that we are like Swiss cheese, with no requirement that all the utilities had to join the CAISO,” said Deborah Le Vine, CAISO director of infrastructure contracts and management. “We have a total of, believe it or not, [19 potentially] affected systems, and out of [them], two are [FERC] jurisdictional.”
Seeking a FERC Fix
“We’d love for you to tell us a fix, because all the ideas we’ve come up with haven’t worked so far,” Le Vine said. “The challenge has been trying to put together any type of reciprocity agreement. That’s why we don’t have the ‘teeth’ to mandate compliance.”
Brian Fritz, director of transmission development at PacifiCorp, said that since the inception of the company’s interconnection queue, it has received more than 1,000 requests for interconnection totaling over 90 GW. “I heard the term ‘Swiss cheese,’ but ours is Swiss cheese on steroids,” Fritz said. “We’re interconnected with many, many different utilities because we have such a large footprint across the west.”
Lisa Szot, head of transmission and interconnection for Enel Green Power North America, bemoaned the lack of a standardized process for affected-system studies. “It would be nice to have something that forces the affected systems to have to complete a study within the time frame of associated areas to meet the timelines of the interconnection process,” she said.
Scott Seier, vice president of private equity firm and generation investor Tenaska Capital Management, said he preferred FERC direction to lengthy RTO stakeholder processes.
“FERC leadership is vital and necessary to ensure problems plaguing processes are addressed to ensure the efficient processing of the interconnection queue and foster competitive and robust markets for electricity,” Seier said. “Looking at the narrow issue of affected-system study coordination, fixes include limited scope of studies in the early stages, increased RTO study resources and allowing interconnection customers to fund affected-system or other interconnection study work to ensure interconnection agreements can be achieved by a certain date.”
Cost Allocation
Commission staffer Tony Dobbins asked MISO Director of Resource Utilization Vikram Godbole if the RTO calculated cost responsibility on a case-by-case basis, “or has it been pretty much a standardized process or document that may have a couple of variations for each entity?”
Godbole said that MISO’s documentation could be improved to provide more detail to customers at the front end of the process.
“We need to keep in mind how far RTOs have come from a coordination perspective,” Godbole said. Older tariff versions lacked any coordination process, he said.
“About the geography of the upgrades, it doesn’t matter whether it’s 600 miles away or a thousand miles away, it comes down to electric impact that has to be mitigated,” Godbole said. “Upgrades will be identified, and somebody’s going to have to pay those. … We have to keep going with our process, the way we’re doing, look for more feedback from stakeholders. And any guidance FERC wants to provide would be helpful.”
EDF Renewable Energy Project Engineer Anton Ptak said the industry needed tariff provisions to detail how costs are allocated and how models are established between affected systems and host transmission providers.
Rock Falls Wind | EDF Renewable Energy
“One thing we’d like to see is specific tariff requirements on affected systems to perform their affected-system studies and provide results when required under the host transmission provider,” Ptak said. “We’ve experienced several delays with affected systems providing their results to MISO in the recent past, and so we’d really like to see some specific language improving the provision of the affected-system study results.”
Szot agreed that cost estimates need to be provided early in the process.
“The affected systems need to provide base case models so an interconnection customer can try to assess potential costs,” Szot said. “For an interconnection customer, the costs that can occur from an affected system could make the project no longer viable. This is a huge commercial risk to developers.”
Small Utility Perspective
James McFall, manager of electric resources for the Modesto Irrigation District in the Central Valley of Northern California, gave the perspective of a smaller — 560 square miles and 114,000 customers — utility. MID is not a member of CAISO but is an affected system of other systems that are connected to the ISO. As such, it has no ability to control dispatch on generators connected to the host system to manage reliability events, McFall said.
The utility must spend significant staff time and resources on affected-system studies, he said. The utility mitigates costs by waiting until certain milestones are met to maximize potential that projects that are studied will be developed.
“Any cost impacts caused by generators interconnecting to third-party systems are borne by MID’s ratepayers if MID is unable to recoup or avoid the costs created by those interconnections,” he said.
McFall said MID is not in favor of standards for affected-system coordination, and he asked FERC to “consider collateral impacts on smaller entities such as ourselves” if it considers standards.
Interconnection-wide Models?
Tradewind Energy Transmission Manager Aaron Vander Vorst said that the industry has been left to navigate its way through affected-system studies because of the “unscripted process” of Order 2003, including managing departures from the pro forma interconnection procedures.
He proposed a concept of “One Model, One Queue, One Schedule,” including jointly developed interconnection-wide transmission models to improve accuracy and efficiency between systems.
Affected systems should be able to do studies on their own queues and neighboring queues simultaneously to encourage cross-seam coordination, he said. And he said the study schedule should be aligned between neighboring providers to ensure developers have the information they need to make informed milestone decisions.
“Taken to the extreme, use of identical dispatches across seams would largely eliminate the need for affected-system studies,” he said.
“The existing rules, procedures and coordination procedures are simply not adequate for the environment that we have found ourselves in today,” he said, “but change is difficult.” The industry needs clear directives from FERC, he said.
First Solar Development Interconnection Manager Madeleine Aldridge, whose company developed about one-third of utility-scale solar serving California, said CAISO has improved its processes by notifying affected systems at an earlier stage. But, she said, “more needs to be done to incent the host transmission owners to take on the coordination that will provide interconnecting generators certainty and best siting incentives relative to existing transmission.”
Texas Solar Project | Tradewind Energy
Aldridge said her the company has waited for as long as two years for affected-system studies. Under current rules, “we are not really sure when we will get the studies report,” she said.
“The concept of coordinated regional planning has not yet touched the generator interconnection process in an efficient manner,” she said. “The Bulk Electric System is really one grid, except for a few exceptions, and really cannot, and should not, be planned for in discreet sections. With well-planned generation, interconnection study processes, regional coordination that includes utilities outside the boundary of the host transmission owner, can increase least-cost solutions, versus disjointed expensive transmission upgrades.”
But Jay Caspary, director of research development and tariff studies for SPP, said an interconnection-wide transmission planning and interconnection process is impractical in the Eastern Interconnection.
“Our [generator interconnection] models — all the models we use for tariff services whether its transmission service or generator interconnections — are based upon our [integrated transmission plan] model,” he said. “I can’t imagine us trying to do that in one effort. Those are big efforts individually by themselves.”
FERC on Monday rejected EDF Renewable Energy’s request that MISO be required to devise a special fast-track option in its interconnection queue for projects that can demonstrate readiness for development.
EDF filed the complaint early this year, asking FERC for a “workable” interconnection timeline to ensure that wind developers can secure federal production tax credits before they expire at the end of 2020. (See Renewables Developer Escalates MISO Queue Design Dispute.)
| AES
The company said MISO’s year-old, three-phase interconnection queue process is only worsening the backlog of waiting generators and sought a one-time “fast track definitive planning phase mechanism” for generators with at least 80% of site control secured and 10-year power purchase agreements for at least 50% of their capacity.
EDF argued that the RTO is now in a “position far from what it justified using the three-phase process for the 2016 and 2017 definitive planning phase cycles.”
In its April 2 order, FERC said study delays in the interconnection queue are not reason enough for the commission to order MISO to create an accelerated queue option (EL18-55).
“We find that the delays experienced by interconnection customers do not make the existing queue process … unjust and unreasonable,” FERC said.
The commission reminded EDF that the RTO only has to make “reasonable efforts to meet its interconnection queue deadlines” and said that there are factors outside of the RTO’s control affecting the queue.
“EDF has not shown that MISO is performing other than in accord with what the Tariff requires. While we understand that MISO’s revised queue process is intended to minimize delays, interconnection customers are not guaranteed that MISO will meet its projected deadlines,” FERC said.
E.ON Climate and Renewables North America had filed in support of EDF’s complaint and said delays in the RTO’s generator interconnection study process is leaving some developers in “serious jeopardy” over whether they would receive tax credits.
However, FERC agreed with MidAmerican Energy’s contention that wind developers could use the RTO’s provisional generator interconnection agreement to achieve commercial operation before the PTC expires.
Further, MISO has pledged that most transition plan interconnection customers will be eligible for generator interconnection agreements in time to qualify for the tax credit, FERC said.
“We are not persuaded that the existing queue process will result in the commercial harms claimed by EDF,” the commission said.
FERC also agreed with MISO’s argument that EDF had not demonstrated that any part of the current generator interconnection process was unreasonable or discriminatory. But it rejected the RTO’s argument that EDF’s proposed remedy and complaint would undermine the stakeholder process used to design the new queue.
No Ringing Endorsement
However, FERC made clear that its denial of EDF’s complaint was not a show of support for MISO’s current queue design.
“While we find that MISO’s performance of interconnection studies and its [generator interconnection process] have not been shown to be unjust and unreasonable, the repeated and significant delays experienced by interconnection customers in MISO are nevertheless a cause of great concern, as they have resulted in considerable uncertainty for interconnection customers in MISO’s queue,” the commission said. “We understand that the achievement of a [generator interconnection agreement] in a timely and reasonably predictable manner is vital to the development of all new generation in MISO and that MISO’s ongoing queue processing delays are a significant problem for generation developers.”
FERC also noted that while the RTO “is somewhat unique in terms of the sheer volume of interconnection requests it receives,” it is not aware of any other RTO plagued with similar delays. It noted the technical conference it held this week focusing on affected systems-related interconnection issues hampering the construction of renewable projects. (See related stories, Renewable Gens Face Off with RTOs at Seams Tech Conference and Developers, Tx Providers Seek FERC Direction on ‘Affected Systems’.)
FERC urged MISO to consider improvements to its queue, telling it should look to other RTOs for best practices and examine whether additional resources would alleviate queue delays.
Idaho Power and Powerex began transacting in the Western Energy Imbalance Market (EIM) on Wednesday, bringing to eight the number of members participating in CAISO’s regional real-time market.
The expansion equips the EIM to serve imbalances for about 55% of load in the Western Interconnection, according to the ISO. It and the market’s seven other members serve more than 42 million customers in an area stretching from the U.S.-Canada border south to Arizona, and from the West Coast east to Wyoming.
| CAISO
“The Western Energy Imbalance Market continues to demonstrate that coordination of energy over a large area can lower costs for electric customers and reduce the cost of the transition to a more renewable-based grid,” CAISO CEO Steve Berberich said in a statement. The market has yielded more than $288 million in benefits for its members since being launched in November 2014.
Idaho Power
Boise-based Idaho Power serves about 542,000 customers across a 24,000-square-mile territory in southern Idaho and eastern Oregon. The core of the utility’s generating portfolio is 17 low-cost hydroelectric projects that serve most of its demand. The company also operates about 4,800 miles of transmission.
“We believe customers will see benefits from the EIM over time, and we expect those benefits to increase as more utilities join the market,” Idaho Power Vice President of Power Supply Tess Park said in a statement.
The utility’s service territory is adjacent to the balancing areas of EIM members NV Energy and PacifiCorp-East (PACE), providing increased transfer capability with the wind-rich area of western Wyoming in the remote northeastern corner of PACE.
Although wind developers see the region as a promising source of exports, transmission constraints — and California’s restrictions on renewable imports not delivered directly into an in-state balancing area — have impeded development of large-scale projects to serve the state. Idaho’s entry into the EIM could open the door for development, expanding renewable portfolio standard eligibility for a larger pool of resources.
Participation in the EIM will also allow Idaho Power to more easily unload the output of excess wind power the utility has been required to contract for under the 1978 Public Utility Regulatory Policies Act. In 2010 — before tightening PURPA eligibility rules — the Idaho PUC received applications for 500 MW of such projects. The minimum system load for Idaho Power, the state’s largest utility, is about 1,100 MW. The utility is still contending with wind developers moving projects across the state line to its service territory in Oregon, where PURPA avoided-cost rates are higher. (See FERC Conference Debates PURPA Costs, Purchase Obligations.)
“Covering a broad territory with a wide variety of resources will help Idaho Power manage our operations and integrate the growing volume of renewable energy sources on our system,” Park said.
Powerex
Vancouver-based Powerex, which markets the surplus generation of parent BC Hydro, becomes the first non-U.S. member of the EIM. (See Power Slated to Become First Non-US EIM Member.) While the company does not directly bring any generation assets into the market, its access to BC Hydro’s ample hydroelectric resources positions the company to provide EIM participants with the flexible ramping capacity needed to firm up the growing number of variable renewable resources coming into the region’s grid.
The company also holds transmission rights on lines throughout the West, including the California-Oregon Intertie, a key transfer point between the Pacific Northwest and California. Constraints on that line periodically isolate the PacifiCorp West and Puget Sound Energy balancing authority areas from the rest of the EIM, resulting in prices that diverge from the rest of the market.
Powerex has actively participated in CAISO’s five-minute market since 2005 through a dynamic scheduling arrangement, but its membership in the EIM will allow it to engage in sub-hourly transactions across multiple balancing authority areas. The ISO worked with Powerex to develop an EIM participation framework addressing the company’s unique situation as a Canadian entity, which FERC approved last year. (See FERC Approves Powerex EIM Agreement.)
Also slated to join the EIM are the Sacramento Municipal Utility District in April 2019 and Salt River Project, Seattle City Light and the Los Angeles Department of Water and Power in April 2020.
CAISO last year proposed to extend its day-ahead market across the EIM, a move that would fall short of creating a full RTO and require members to relinquish control of their transmission assets. (See Peak/PJM Enter Western Market ‘Commitment Phase’.)
ISO-NE is moving to keep the 1,998-MW Mystic Generating Station running to ensure grid reliability following Exelon’s March 29 filing with the RTO to retire the plant in 2022.
Chief Operating Officer Vamsi Chadalavada on Tuesday sent a memo to the New England Power Pool Participants Committee outlining the grid operator’s “limited” options ahead of a planned discussion of the issue at the committee’s April 6 meeting.
Mystic Generating Station
Exelon last week said it “may reconsider” the decision to retire Mystic if the grid operator can reform its markets to properly value the plant’s contributions to reliability and regional fuel security. (See Mystic Closure Notice Leaves Room for Reversal.) The Everett, Mass., facility includes a 576-MW dual-fuel unit (Unit 7); two gas-fired units capable of producing a combined 1,414 MW (Units 8 and 9); and Mystic Jet, an 8.6-MW oil-fired peaker.
On the same day it issued the retirement notice, the company also announced it will purchase the Everett Marine (Distrigas) Terminal — an LNG import facility — from ENGIE North America “to ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating.”
Distrigas Terminal | ENGIE
“Since the ISO received Exelon’s retirement bids, it has been analyzing the potential impacts of losing the Mystic and Distrigas facilities from a fuel security perspective,” Chadalavada said in the memo.
He highlighted the reliability impacts identified in the RTO’s recent Operational Fuel Security Analysis and the limited time to address the issue. (See Report: Fuel Security Key Risk for New England Grid.)
The RTO will ask FERC to waive its Tariff requirements to allow it to retain Mystic 8 and 9 to maintain fuel security on the system, he said.
ISO-NE CEO Gordon van Welie said in February that that the RTO might need to seek such authority for resources required for regional fuel security. (See Van Welie: ISO-NE in ‘Race’ to Replace Retirements.)
In addition to discussion at the April 6 NEPOOL Participants Committee meeting, ISO-NE will meet with its stakeholders to explain its reliability analysis of the retirement bids immediately following the RTO’s April 10 Markets Committee meeting, Chadalavada said.
“We plan to commence discussions with stakeholders, beginning at the April 25 Reliability Committee meeting, on the necessary reliability criteria for retaining resources needed for fuel security in the Forward Capacity Market,” he said.
Citing reliability issues focused on transmission security, the RTO rejected the dynamic delist bids for Mystic Units 7 and 8 in Forward Capacity Auction 12, which covers 2021/22.
Oil supplies at plants in New England declined rapidly during a cold snap earlier this winter as gas prices spiked and dual-fuel plants switched to oil, but the RTO avoided serious reliability issues thanks to LNG shipments.
The Distrigas Terminal — which the RTO said is the only fuel supply source available to Mystic units 8 and 9 — is the oldest such LNG facility in the U.S. and has connections with two interstate pipeline systems, the Tennessee and Algonquin pipelines, as well as with the local distribution system owned by National Grid.
