The Virginia General Assembly passed a bill Thursday that would temporarily suspend the State Corporation Commission’s biennial review of Dominion Virginia Power’s base rates.
SB 1349, introduced by Republican Sen. Frank Wagner, was written with help from Dominion. It would freeze the utility’s base rates while preventing the SCC from reviewing those rates after the scheduled 2015 review until 2020.
Dominion would still be able to request increases for fuel and infrastructure costs. It has already promised not to pass along $85 million in fuel costs to ratepayers as part of its support for the bill.
The bill passed the state Senate 32-6 on Feb. 6 before clearing the House of Delegates 72-24 last week. Support and opposition to the bill were both bipartisan. The bill now goes to Gov. Terry McAuliffe (D), who can veto it, though under Virginia law the legislature may override the veto with a two-thirds majority in each house.
Wagner has said he introduced the bill to prevent rate increases that would occur due to coal retirements under the U.S. Environmental Protection Agency’s proposed carbon emissions rule, called the Clean Power Plan. Wagner was among 11 senators who owned stock in Dominion, but earlier this month he told the Associated Press that he sold it because he didn’t want to be perceived as profiting from the bill.
State Attorney General Mark Herring (D) has come out against the bill, as have consumer advocate and environmental groups. The Sierra Club, however, dropped its opposition after Dominion promised to invest in 500 MW of solar generation.
PJM’s proposal to exempt transmission upgrades under $20 million from a $30,000 study fee is unduly discriminatory, the Federal Energy Regulatory Commission ruled Friday.
LS Power proposed the compromise after an earlier proposal, which would have charged only new “greenfield” transmission facilities, fell short of a two-thirds majority. The proposed compromise would have assessed the fee on upgrades of $20 million or more as well as all greenfield transmission proposals.
LS Power and other non-incumbent transmission developers had contended the original proposal was unfair because it applied to greenfield projects only.
PJM officials said that upgrades by transmission owners typically did not require the intensive engineering analysis that the fee is intended to pay for.
The Members Committee approved LS Power’s compromise with an 84% sector-weighted vote.
But the commission ruled that PJM failed to show that the costs of studying transmission owner upgrade proposals with estimated costs under $20 million would be different than the costs of studying greenfield projects with similar costs.
“Even though PJM’s proposal represents a compromise among stakeholders, PJM’s proposal is inconsistent with the requirements of Order No. 1000,” the commission said.
VALLEY FORGE, Pa. — An attempt by PJM officials and the Independent Market Monitor to complete what they called unfinished business ran into a roadblock last week as several stakeholders questioned their authority, saying members should consider a new problem statement.
Officials are seeking manual changes to document rules on generator notification and start-up times they said had been authorized by members — but never implemented — in 2012.
The issue dates to a January 2011 problem statement to address reliability and market implications of generators’ desire to “de-staff” little-used units during the spring and fall shoulder months. At the time, there were no market rules governing start time and notification time parameters.
PJM and the Monitor said the Operating and Market Implementation committees approved rule changes in 2011 and 2012 but that manual changes endorsed by the Markets and Reliability Committee in June 2012 implemented only part of the “solution.”
The MRC endorsed the addition of a new section 1.4 to Manual 10 and made revisions to manuals 13 and 14D. The changes defined what happens when PJM issues a notification or start-up alert, and set notification and start-up time requirements for peak and off-peak periods.
Last week, officials told OC and MIC members they want to add a section to Manual 11 that would fully implement the rule changes. The new language, which is still being drafted, would:
Require units to use the same notification and start-up times for both price-based and cost-based offers;
Define “safe harbor” provisions for units whose notification and start-up times don’t affect PJM scheduling decisions;
Establish an economic indicator in eMKT that signals to generation owners whether the Monitor anticipates their units will be economic or uneconomic;
Add an approval and change process for notification and start-up time parameters; and
Establish rules on start-up cost offers for short lead-time units.
Lost in the Ether
Dave Anders, director of PJM stakeholder affairs, said his research found that manual language was drafted for elements involving PJM but not for those concerning the Monitor’s role in enforcing the rules.
“They were never drafted and taken to the MRC and for some reason we closed this issue out in the issue-tracking and it got lost in the ether,” Anders told the MIC on Wednesday.
But some members who took part in the 2012 MRC vote said their recollections of the issue differ from the portrayal by PJM and the Monitor.
One stakeholder said the Manual 11 changes the Monitor is now seeking would allow it to approve both cost- and price-based schedules. “I’m telling you that would not have been approved” by members, said the stakeholder, who declined to be quoted by name.
Members “did not come to any resolution on what an appropriate notifying time would be except for … long lead-time units,” he told the OC on Tuesday. “Never did we agree that the start-up and notification was subject to approval by the Market Monitor.”
Several stakeholders said members should consider a new problem statement on the unapproved manual changes and other concerns that generators have regarding parameter-limited schedules.
A second stakeholder who also declined to be quoted by name asked whether there was a “statute of limitations” on problem statements, saying it “seems like a stretch” for officials to make the changes years later. “Everybody who was a part of the process has different recollections of what was agreed on,” he added.
Joel Romero Luna, representing the Monitor, told the OC that PJM and the Monitor have been unable to find any documentation “that things were purposely kept out.”
“Some things were implemented. Some things were not implemented,” said Luna, who was not part of the 2012 discussions.
“There was a reason that it didn’t” get implemented, the second stakeholder responded. “Because the [members] didn’t come to agreement on everything on the Market Monitor’s wish list.”
Meeting Minutes
Minutes of the March 14, 2012, MIC meeting record members’ unanimous approval of two related items. An agenda item titled “parameter limited schedules” reports that Marker Monitor Joe Bowring “reviewed the consensus proposal that resulted from the special sessions of the MIC, which focused on developing potential solutions to the issues identified with the application of parameter-limited schedules to only cost-based offers.” (Emphasis added.)
Under a second agenda item titled “unit notification and startup time,” the minutes report that PJM’s Simon Tam “reviewed the consensus proposal resulting from the special sessions of the MIC, which focused on addressing market-related issues stemming from the operational requirements for units with extended notification and start-up time. The proposal will be implemented once the required technical changes are in place, but no sooner than fall 2012.”
Minutes of the June 28, 2012, MRC meeting, at which members endorsed the earlier manual changes, are no longer publicly available on the PJM website.
What’s the Rush?
Mike Borgatti of Gabel Associates noted that the Federal Energy Regulatory Commission’s response to PJM’s Capacity Performance proposal could result in additional rule changes. “What’s the rush with putting this into effect now?” he asked. “That’s a very contentious piece of the filing.”
Path Forward
MIC Chair Adrien Ford said the manual changes would be brought to a first read at the committee’s March meeting, at which time members will consider whether to move forward or to seek a new problem statement. PJM intends to refer a provision allowing generators to include the cost of shortening notification and start-up times in the cost-based start-up cost to the Cost Development Subcommittee.
Ford said that in the interim, PJM, the Monitor and stakeholders will “seek agreement on what was the history” of the issue.
The Coalition of MISO Transmission Customers (CMTC) has asked the Federal Energy Regulatory Commission to reconsider its approval of a 50-basis-point incentive adder for MISO membership.
FERC conditionally approved the adder last month, saying that the resulting base return on equity must be in the zone of reasonableness — 7.03 to 11.74%. The commission said that industrial customers, including the CMTC, had failed to provide sufficient evidence for their argument that TOs did not need an incentive to remain in the RTO. (See MISO TOs Can Collect Membership Adder — Once Base ROE is Found Just.)
In its rehearing request, the coalition said that FERC’s ruling violated Section 205 of the Federal Power Act, which holds that the burden of proof in a ROE-related filing falls on the filers, not the complainants. FERC “not only failed to hold the MISO [transmission owners] accountable for demonstrating that the RTO adder in this case is just and reasonable, but also effectively, and erroneously, shifted the burden onto protestors to show that the RTO adder is unjust and unreasonable,” the coalition said (ER15-358).
MISO TOs requested the adder last November. Industrials criticized the adder as an attempt to hedge against a potential decrease in the TOs’ base return on equity, which industrials have contended is too high. Settlement talks between the TOs and industrials broke down in December.
MISO planners recommended Wednesday that Entergy’s request for a $187 million transmission upgrade near Lake Charles, La., be sent up the line for consideration by the RTO’s board, despite continued objections from transmission developers.
“I know there are some contentious issues around this,” Jeff Webb, MISO’s director of planning, acknowledged shortly after opening a discussion of the project at a meeting of the South Technical Study Task Force in Metairie, La.
On Dec. 15, Entergy Gulf States Louisiana filed an out-of-cycle request with MISO, saying the need for the transmission upgrade was identified on Dec. 1. Entergy told MISO that increased industrial demand for power requires it complete the Lake Charles project by June 2018.
The company requested that the project be treated as an out-of-cycle project outside of the usual MISO Transmission Expansion Planning (MTEP) process and the competitive solicitation rules under the Federal Energy Regulatory Commission’s Order 1000.
At MISO’s Planning Advisory Committee meeting Jan. 28, transmission developers questioned the timing and motives behind Entergy’s request, which would deny them a chance to compete for the project. (See Entergy Out-of-Cycle Transmission Request Draws Competitors’ Ire.)
Webb started last week’s meeting by spending more than 30 minutes explaining MISO’s transmission planning rules, which limit out-of-cycle requests to reliability projects identified after the submittal cutoff date of the prior annual MTEP cycle with a need date within three years of the request date and expected in-service date within four years.
“We see the [Lake Charles] projects as fitting [the out-of-cycle] requirements,” Webb said.
Stakeholders Dubious
But, as during last month’s PAC meeting, stakeholders questioned how Entergy could only recently decide it needed the project and whether it needed to be done on a fast-track outside the MTEP.
A representative of NRG Energy asked Webb whether MISO had done any due diligence or simply took Entergy’s word “at face value.”
MISO officials replied that they are aware of substantial growth in the Gulf Coast region and that Entergy’s Module E load forecast data was consistent with the amount of load growth that’s been represented in the Lake Charles project. It would include two new substations, expansion of another and 25 miles of 500-kV and 230-kV transmission.
Edin Habibovic, manager of expansion planning at MISO, said that between MTEP 14 and MTEP 15, an additional 617 MW of growth was identified. Without upgrades, the increased loads could result in North American Electric Reliability Corp. violations due to overloaded transmission lines and voltage issues, Habibovic said.
George Dawe, vice president of Duke American Transmission, said evidence provided by Entergy amounts to anecdotal information.
“In our view, what’s the urgent need? I don’t see it anywhere. … It’s not a baseline reliability project,” Dawe said.
MISO officials said they have talked with Entergy’s industrial load customers, but that the customers haven’t been transparent about the timing of their power needs. Habibovic said obtaining detailed demand information from individual industrial companies is challenging in part, because they often make decisions at the last minute.
That wasn’t good enough for Dawe.
“A normal planning process has been thrown out the window,” he said. “It’s not a defined new load addition. It speculates on future economic development.”
Webb replied that if MISO ran the proposed project through the developer selection process, it would not meet Entergy’s deadline.
“We can’t risk going through that process and speculate that Entergy is wrong here — that the process could be done in two years versus two and a half years.”
MISO will not let the planning process stand in the way of needed transmission, he added, saying that’s why FERC allows exceptions to the competitive process under Order 1000.
No Attractive Alternatives
Habibovic said MISO has looked at alternatives to Entergy’s proposal to meet the increased demand, including routing power from Beaumont, 35 miles to the west in Texas, and from Lafayette, 50 miles to the east. Also modeled was an update of existing 230-kV lines.
He said the alternatives presented a number of problems, including reliability issues during construction, right-of-way challenges and high-impedance issues.
Kip Fox, director of transmission strategy and grid development at American Electric Power, asked if MISO reviewed recent public filings of electric customers who have deferred plant expansions. Other stakeholders cited reports that the drop in petroleum prices has put some liquefied natural gas projects in the Gulf region in limbo.
An Entergy representative replied that the timing of plant expansions can be volatile. Even if industrials delay a project, the need often resurfaces within a few years’ time, he said.
Cost-Overrun Concerns
Stakeholders also asked whether MISO had conducted due diligence on Entergy’s estimated costs for the project, questioning whether the $187 million price tag may grow.
Webb responded that most state regulatory agencies have provisions to deal with cost escalation and require utilities to justify overruns.
Board Consideration
Entergy’s out-of-cycle request will be discussed again at MISO’s Feb. 18 PAC meeting. It would then proceed to the System Planning Committee of the Board of Directors, likely in March, with potential consideration by the full board in April.
Overshadowed at the Metairie task force meeting by the Lake Charles discussion was a recommendation to approve five other out-of-cycle projects in the region, the largest at $10.3 million.
VALLEY FORGE, Pa. — PJM is developing design, engineering and construction standards for non-incumbent transmission developers who can win “designated entity” status under the Federal Energy Regulatory Commission’s Order 1000.
PJM’s Suzanne Glatz told Thursday’s Planning Committee meeting that the RTO is seeking a balance between “innovative designs” and reliability. Greenfield projects would not have to conform to an incumbent transmission owner’s design standards but would have to meet reliability standards.
A non-incumbent could reference standards filed in FERC Form 715 for other jurisdictions, adhere to standards approved by PJM’s Transmission and Substation Subcommittee or win the subcommittee’s approval for the developer’s own standards.
Voltage Floor Among Changes to Improve Order 1000 Process
PJM is considering changes to improve the Order 1000 process and expects to present a problem statement to the Planning Committee after its fourth and final “lessons learned” conference call on the issue Feb. 27.
One possible change would exempt projects below 200 kV from the competitive process.
Improvements already underway include the use of webcasting, development of a new tool to permit the secure exchange of large files and process improvements to gain access to annual transmission planning and evaluation reports.
Light-Load Study: Generation Up, Load Down
PJM is considering changes to the assumptions it uses for modeling light-load conditions in transmission planning.
“We want to determine whether the assumptions we made four years ago should be revisited,” PJM’s Mark Sims said. “We have a lot more wind now. We have a lot more data.”
An analysis of light-load historical data confirmed that the windiest hours continue to be 1 to 5 a.m. November through April — a time when load often is less than the assumed 50% of the summer peak.
Meanwhile, wind generation often exceeds the 80% capacity factor assumed in the modeling.
Planners will discuss potential changes with stakeholders in March.
DR Assumption Model to Change
PJM is proposing to change the way it models demand response in planning studies to reflect the amount of DR that is replaced by other resources before the delivery year.
Currently, the model relies on the amount of DR that clears the Base Residual Auction and any Incremental Auctions for a delivery year. That amount is held constant for all future years.
One alternative PJM is considering would reduce DR by the lesser of either the locational deliverability area’s existing uncleared generation for the delivery year, or a rolling three-year average of the amount of DR replaced by other resources RTO-wide.
The three-year rolling average ending June 1, 2014, showed about 34% of DR was replaced RTO-wide.
VALLEY FORGE, Pa. — Software problems have led PJM to delay implementation of an eMKT tool allowing gas-fired generators to make intraday changes in price schedules, Chantal Hendrzak, PJM general manager of Applied Solutions, told the Operating Committee last week.
The optional system, called the Intraday Cost Schedule Update, had been set to go live Feb. 9. It is now expected to go into production Feb. 23. The changes, intended to more accurately reflect the cost of generation, will allow users to file a different cost schedule for each hour every day, not just during cold weather alerts.
Implementation was delayed in part because of coding that required members to upload fuel information with every single entry. That is being changed so members will be able to download all fuel types and upload them in XML.
Once the update is functional, the previous manual process will no longer be supported.
Additionally, fuel data enhancements in eMKT were scheduled to be introduced to the eMKT “sandbox” for testing Feb. 13. Beginning April 1, all members will be required to supply energy fuel type and subtype, as well as startup fuel type and subtype, in order for their offers to be accepted — regardless of whether the generator plans to make intraday price changes.
January Operations Show Improvement
A report on last month’s operations showed that the forced outage rate was much lower than in January 2014, with outages peaking at 10% during an RTO-wide cold weather alert Jan. 7-8.
Gas problems were responsible for about half of the 18,861 MW that failed to operate during the morning peak on Jan. 8 and the 13,481 that faltered on the evening of Jan. 7.
The preliminary reported load for Jan. 8 was 136,669 MW, the fifth-highest winter peak on record. Jan. 7 saw the seventh-highest peak at 136,119 MW.
No units changed their costs intraday during the cold weather alert.
Wind generation during the cold weather event also was good, at 2,500 to 5,300 MW during peak hours.
Cold Weather Preparation Test Fails 10 Generators
PJM tested 168 generators in December and January, and all but 10 were successful.
In all, 443 units were eligible to participate in the exercise. Of those that did, 26 experienced initial failures. In a retest, 16 succeeded.
The largest cause of failure, at 31%, was liquid fuel handling problems, followed by cranking diesel failure and circuit breaker issues, each accounting for 15% of the total. Control system problems made up 12%. The remaining 27% of failures were chalked up to miscellaneous reasons, such as generator instrumentation issues and excessive vibration.
The participating units experienced a significantly lower percentage of forced outages in the first week of January compared with units that either declined or were not eligible to take part.
The cost of the winter testing came to $4.88 million.
Sought: Ways to Incent Training, Certification Compliance
Some PJM generation operators are guilty of “chronic non-compliance” with training and certification requirements, PJM told members.
While non-compliant companies are supposed to submit mitigation plans, many have not, and there are no financial penalties for failing to do so.
PJM officials asked the Operating Committee to consider whether the RTO should impose financial penalties or deny offenders access to PJM markets and tools.
Transmission operators generally are in compliance, officials said.
System Restoration Coordinators Task Force Becomes Subcommittee
Members approved a charter change upgrading system restoration coordinators from a task force to a subcommittee.
The change was made because task forces are supposed to sunset. The subcommittee will report to the Operating Committee.
VALLEY FORGE, Pa. — PJM’s plan to change the definition of the IMO interface with Ontario’s Independent Electricity System Operator received a lukewarm review from Market Monitor Joe Bowring, who said it would not correct what he has called “sham scheduling.”
“We think it’s an improvement. We don’t think it resolves it,” Bowring told the Market Implementation Committee last week, saying he would determine its effectiveness by the prices that result.
In 2013, the MIC approved Bowring’s request to investigate whether traders could be manipulating PJM’s interface pricing points by breaking schedules into multiple “back-to-back” transactions. (See MIC to Probe ‘Sham Scheduling’.)
In the 2012 State of the Market report, the monitor described the practice as “sham scheduling,” in which he said traders were hiding the actual source of generation. PJM prices transactions with external balancing authorities based on the source and sink identified on the North American Electric Reliability Corp. eTag. Breaking the transaction into portions with separate eTags can lead to loop flows and incorrect pricing.
The IMO interface pricing point was created because transactions that originate or sink in Ontario IESO balancing authority create flows that are split between the MISO and NYISO interface pricing points. The Monitor wants PJM to eliminate the IMO pricing point and assign transactions that originate or sink in IESO to the MISO interface pricing point.
Bowring said that he may recommend banning some transmission paths to prevent the abuse, as NYISO did in 2008 (ER08-1281).
New Definition
PJM’s new definition recognizes that flows from transactions scheduled between IESO and PJM are affected by the performance of the Michigan-Ontario phase angle regulators (PARs).
Because actual flows are not known in advance, the price will reflect historical flows over the PARs, using an average price split weighted with 40% NYISO and 60% MISO.
The new definition, which will be effective with the new planning year beginning June 1, will be used in both the annual financial transmission rights auctions and auction revenue rights allocations.
In addition, a new aggregate, named “ONTARIO,” will be created that maintains the current IMO definition in order to eliminate impacts to long-term FTR positions. It will be defined as 100% of the BRUCEA 17-kV pnode. It will also become effective June 1.
PJM says critics of its requests to safeguard capacity for the 2015/16 delivery year ignored the context of its filings with the Federal Energy Regulatory Commission.
Fearing that it might run short due to retirements of coal-fired generation, PJM asked for a one-time waiver on rules that would otherwise require it to release 2,000 MW of capacity in the Feb. 23 third Incremental Auction for 2015/16 (ER15-738). Dominion Resources called the filing “premature and speculative.” (See PJM Capacity Release Filings Draw Critics.)
PJM countered that “Dominion ignores the resource adequacy planning context of PJM’s request. By its very nature, planning is forward-looking and prudently anticipates a variety of possible conditions and scenarios. Dominion’s argument is comparable to contending that the possibility that loads could substantially exceed forecast levels this summer is ‘premature and speculative;’ or that the possibility that forced generation outages could greatly exceed average levels next winter is ‘premature and speculative.’”
PJM also dismissed arguments that the 2,000-MW figure was too broad, saying that it is barely more than 1% of the resources committed in the Base Residual Auction for this delivery year.
PJM also proposed revising its Tariff to allow it to enter into capacity agreements made outside the Reliability Pricing Model auctions (ER15-739).
In its protest, Old Dominion Electric Cooperative argued that PJM had “not demonstrated a threat to reliability sufficient to warrant its proposal for undefined and unlimited authority to enter into agreements” outside of the RPM. It also said that “no [reliability-must-run] procurement should be pursued or entered into without further being informed by the third Incremental Auction results.”
PJM said that it appears that the amount of uncommitted resources is not enough to meet the potential capacity deficiency. “Therefore, PJM likely cannot rely on the third Incremental Auction as a source of supplemental capacity to increase overall capacity commitment levels and help mitigate the identified resource adequacy concerns,” the RTO said.
PJM also disputed the allegation made by Direct Energy that the RTO is seeking a “blank check.”
“PJM showed in the Dec. 24 filing that if generator outage and peak load conditions like those seen in January 2014 were to recur in the 2015/2016 winter, the PJM region could be short by up to 2,600 MW,” the RTO said. “PJM therefore is seeking supplemental capacity agreements of no more than 2,600 MW.”
PJM is asking FERC to approve its proposals before the third Incremental Auction on Feb. 23.
Electric cooperatives operate in 93 of North Carolina’s 100 counties.
The North Carolina Electric Membership Corp. is protesting a request by Dominion Resources to push back the effective date for a rate revision by more than a year.
Last April, the Federal Energy Regulatory Commission approved Dominion’s request for revised transmission depreciation rates with an effective date of April 1, 2013 (ER14-1549).
On Jan. 15, Dominion asked FERC to change the effective date to Jan. 1, 2012, saying its request would only change the effective date of the revised rates, not the rates themselves.
NCEMC, however, says that Dominion’s request would run afoul of the commission’s prohibition against retroactive ratemaking.
“This filing effectively seeks to retroactively charge increased rates to Dominion’s transmission customers for transmission service purchased during the locked-in period Jan. 1, 2012, through March 31, 2013,” NCEMC said in its protest (ER15-856).
Dominion is requesting the extension because of a Virginia State Corporation Commission ruling that set the 2012 date for the updated depreciation rates for bookkeeping purposes. The SCC filed comments in support of Dominion, saying that its precedent holds that a “change in costs must be recorded in the appropriate accounting period coincident with the change; this is true for depreciation expense as well as other costs.”
“Thus, while Dominion correctly notes that its filing is necessitated by the directive of the [SCC] … this implementation date is also consistent with sound utility accounting practice,” the SCC said.
NCEMC argues that, based on prior similar cases, FERC “is not bound by state determinations regarding retail rate proposals. And Dominion cited no precedent to indicate that other commission policy considerations require consistency between state and federal depreciation rates, plant balances or depreciation reserves.”
