An August 2015 report by the Rocky Mountain Institute said that although the Supreme Court ruling would be “immensely important” for demand response, the industry was limited by “traditional, top-down grid paradigms.”
“By focusing on DR’s revenue potential in wholesale markets, a huge part of the core value proposition of demand flexibility is lost — namely, the economic benefits of flexible, controllable demand to individual customers,” it said.
The institute’s co-founder, Amory Lovins, is credited with inventing the term “negawatt” — power saved through conservation or efficiency.
The institute’s new report, The Economics of Demand Flexibility, coins a new term, “flexiwatts” — demand that can be moved across the hours of a day or night based on economic or other signals.
The report concludes that residential demand flexibility can save $9 billion per year in spending on transmission investments — a cut of more than 10% of forecast spending — and $4 billion annually in energy production and ancillary services. That could reduce consumers’ electric bills by 10% to 40%.
Flexiwatts can reduce capacity spending by reducing peak loads and flattening aggregate demand profiles of customers. In the energy market it can shift load from high-price to low-price times. They can also reshape load profiles to complement the increasing intermittent generation expected in response to EPA’s Clean Power Plan.
While DR is deployed infrequently and often used only as a last resort during peak demand, demand flexibility can be used continuously and proactively to reduce costs year-round, resulting in direct bill reductions instead of infrequent incentive payments.
Demand flexibility can use automatic controls to reshape a customer’s demand profile in ways that either are invisible to the customer (for example, using storage to decouple the timing of consumption from the grid impact) or minimally affect the customer (shifting the timing of non-critical loads within customer-set thresholds).
It also takes advantage of time-of-use or real-time pricing, demand charges and distributed solar PV export pricing to provide retail price signals directly to customers or through third-party aggregators.
Despite posting a decrease in revenue and missing analysts’ predictions, American Electric Power last week reported a 145% increase in fourth-quarter earnings, from $191 million ($0.39/share) in 2014 to $469 million ($0.96/share) in 2015.
The jump in earnings reflected the sale of the company’s barge business, AEP River Operations, for $550 million to American Commercial Lines in October.
The company showed fourth-quarter revenue of $3.6 billion in 2015, less than the $3.8 billion it pulled in the same period last year and the $3.87 billion analysts had expected.
View from an AEP Barge (AEP River Operations)
Despite the weak fourth-quarter revenue, it was a good year for AEP, which reported a 25% increase in earnings from 2014 off of only slightly higher revenue.
“Our strong 2015 earnings performance demonstrates that ongoing investment in our core, regulated operations is the right way to deliver enhanced service for our customers and value for our shareholders,” CEO Nick Akins said. “We increased our earnings guidance twice in 2015 and achieved earnings performance solidly within our revised range, despite extremely warm temperatures in the fourth quarter.”
In AEP’s earnings conference call on Thursday, Akins said that “winter, particularly in December, never occurred; it was more like April.” Akins also blamed a weak economy late in the year — as global markets fluctuated and oil prices continued to decline — for the less-than-expected revenue.
The miss, however, has not seemed to faze investors. AEP’s stock price spiked on news of the earnings, opening before the earnings release at $57.13 Thursday and closing out the week at $60.97. Earnings from AEP’s vertically integrated utilities more than doubled in the fourth quarter and increased 26.7% year-over-year, reflecting positive rate cases and lower expenses. The company’s transmission business also contributed to the earnings increase, both in the fourth quarter and for the full year.
Akins was confident that the company’s proposed power purchase agreement in Ohio, which would provide a guaranteed return for its embattled generating stations for eight years, would be approved by regulators, despite a recent call by independent power producers for FERC to void the deal. (See Dynegy, NRG Ask FERC to Void Ohio PPAs.)
Akins cited the settlement AEP reached with Public Utilities Commission of Ohio staff and other stakeholders, including the Sierra Club. “This arrangement, when approved by the Ohio commission, will be a model that can be used nationally that sets the tone for parties with substantially different positions about generation resources and the pace of change to come together, focusing on the clean energy future and the mitigation of transition cost increases that our customers and the public expect,” the CEO said during Thursday’s call.
AEP’s operating earnings per share for 2015 was $3.69, compared to $3.43 in 2014. The company reaffirmed its earnings guidance of $3.60 to $3.80 for 2016.
Faster Path to Market for Distributed Resources to be Studied
WILMINGTON, Del. — A problem statement and issue charge that initially focused on the path for distributed battery storage systems to enter PJM markets failed to gain support at the Markets and Reliability Committee on Thursday until presenter Drew Adams rewrote the documents to address all distributed resources.
Adams, of battery developer A.F. Mensah, also limited the review to behind-the-meter generation of 20 MW or less. Members approved the revised proposal with one no vote and one abstention.
Currently, distributed resources have two options to join the markets: interconnect as a generation resource through the queue process or register as demand response. Going through the queue is cost-prohibitive and time-consuming for distributed resources, while entering the markets as a demand resource limits the value they can provide, Adams said.
PJM Vice President of Planning Steve Herling said a discussion will be useful. “More recently, we’ve had a number of these very, very small projects, but they can get into service much faster than the queue process. We have been trying to work within the bounds of the Tariff. We’re probably at the limit of what the words in the Tariff can accommodate,” he said. “We’re certainly in favor of looking at it in light of the number of requests we’ve had.”
John Horstmann of Dayton Power & Light suggested in the initial discussions that the problem statement be broadened to include other types of generation, including distributed generation. The generation interconnection queue, he said, “was set up to accommodate units that cleared in [capacity auctions] and then had three years to build for the commercial delivery year. There is now generation that can get connected to the grid much faster than three years.”
Tom Rutigliano of Achieving Equilibrium offered a friendly amendment to include similar resources that face the same types of obstacles.
John Farber of the Delaware Public Service Commission asked if there would be any state jurisdictional issues involved in making changes to the current process.
“Yes,” Adams said. “That is one of the challenges, to identify them and properly address the state versus federal jurisdictional issues.”
Because the issue spans several PJM committees and there is no stakeholder forum to study the issue, it will be discussed at a series of special MRC sessions. Once education and background have been completed, action items will be assigned to a new MRC subgroup or other PJM committees.
Members Unanimously Reject Changing RPM Cost Allocation Method
A problem statement and issue charge proposed by PJM to review whether the cost allocation method for capacity charges should be revised did not garner a single yes vote from the MRC, leading CEO Andy Ott to declare the matter closed.
“At this point, we don’t see a need to take further action,” he said.
PJM allocates the cost of procured capacity based on each transmission zone’s peak load forecast. It also posts the five hours with the highest coincident peak load for the entire RTO.
In its Capacity Performance filing, PJM proposed changing that method and using the coincident peak loads from the most recent calendar year. Given the protests and comments received, however, it asked FERC to postpone ruling on that component until the matter could be addressed through the stakeholder process.
“We continue to believe that the current cost allocation approach is appropriate,” said Susan Bruce, of the PJM Industrial Customer Coalition, in comments that appeared to capture the consensus. “Relying on peak load is consistent with cost causation principles. Therefore, no problem exists.”
Seasonal Resources in the Capacity Market to be Studied
Katie Guerry of EnerNOC received a lot of pushback for a problem statement and issue charge regarding incorporating seasonal resources into the Capacity Performance construct. But in the end, the item, which Guerry presented on behalf of the Advanced Energy Management Alliance’s PJM members, passed on a sector vote with 68% support.
Capacity Performance rules allow aggregation of seasonal resources to convert them into “synthetic” annual resources, but none was submitted in the first Base Residual Auction involving CP. Stakeholders will be asked to consider rule changes to encourage seasonal resources to participate.
It’s unclear, Guerry said, whether the lack of participation was due to the rules themselves or the timing of their release before the auction.
What is clear, she said, is that it will be very expensive to make up for the loss of this base capacity in delivery year 2020/21, when the market goes to full Capacity Performance resources.
Bruce said the ICC supported looking at the issue. “What we’re seeing, between Clean Power Plan initiatives as well as many state initiatives, is more and more resources that may have varying [output]. That might come to a head at the time we see base capacity go away. We need to figure out ways to reflect those resources — from an efficiency perspective as well as from a public policy perspective.”
Marji Philips of Direct Energy requested that PJM and stakeholders devise a comprehensive approach to look at all of the issues arising from the implementation of CP, “so we’re not piecemealing it with problem statements.”
Jason Barker of Exelon, among others, noted that at the time Capacity Performance was approved, FERC rejected seasonal products. Because the reason for the lack of aggregation participation is unknown, he said, the “data point” of the 2018/19 BRA results does not show whether there is a market rule problem.
Guerry was undeterred. “The self-limiting reality of any kind of aggregation model exists no matter what,” she said. “Now we have time to use this process to our best ability to devise appropriate and thoughtful solutions to the auction for the 20/21 delivery year.”
Rejection of Tariff Revision Brings Sharp Words from PJM Counsel
The MRC approved most recommendations from the Governing Documents Enhancement and Clarification Subcommittee, tasked with cleaning up inconsistencies and clarifying definitions in PJM’s governing documents.
But members rejected a revision to the term “alternative dispute resolution,” with only 53.4% endorsing it, shy of the 66.8% threshold.
The revision sought to clarify that legal interpretations of the Tariff can’t be mediated by ADR because FERC has jurisdiction over such matters.
Vince Duane (left)
PJM General Counsel Vince Duane expressed his disappointment at the following Members Committee meeting.
“The vote to me was perplexing. Nothing that took place in that task force was an indication that we wouldn’t get that approved,” he said. “That was a wrong decision.”
ADR is fine if the dispute is factual, he said. However, he said, ADR can’t be used for other disputes.
“Why? You guys spend a lot of time here coming up with rules that get filed at the commission,” he said. “I don’t think you intend those rules to get put in place and then when a dispute comes up,” it’s settled in private.
“And we settle it with your money,” Duane said. “If it’s a factual billing error, that’s fine. But it’s not our prerogative to have the right to deal with your financial interests behind closed doors.”
Task Force will Examine Role of Virtual Transactions
Over one objection, the committee approved a proposed problem statement and issue charge addressing the nodes at which virtual transactions may be made.
The problem statement is intended to initiate stakeholder dialogue over whether any market rule changes should be made. Discussion is expected to take no more than 180 days.
Educational Session will Study Unit Commitment
The sponsor of a problem statement investigating the idea of separating financial day-ahead obligations from the physical unit commitment agreed to defer the matter until after an educational session requested by stakeholders.
Barry Trayers of Citigroup Energy agreed to delay action on the problem statement when it became clear that many stakeholders did not fully grasp the scope of the proposal, and PJM staff agreed that the unit commitment process should be reviewed.
PJM already is working on clearing the day-ahead market more quickly, Trayers said, making it an appropriate time to study ways to identify generation needs faster.
“This is just to investigate a way to separate the commitments of physical units, and do it sooner so generators have an idea of what they’re going to have to do tomorrow,” he said.
Direct Energy’s Philips opposed the idea, saying it might be good for generators but not for load-serving entities.
“I’m so confused I don’t really know where to start. It seems like the basis of what you’re asking is for a total reconsideration of the foundation of PJM. If you separate out day-ahead, how am I as load going to hedge on a daily basis under your proposal to separate financial from physical? Do we just create another day-ahead physical market?”
Responded Trayers, “I would think that load would want this done as efficiently as possible.”
Market Monitor Joe Bowring supported the idea of holding an educational session before moving forward.
“I think Barry’s raised a key issue that needs to be thought through,” he said. “It would be appropriate to have education from a variety of sources, including the [Monitor] and sectors that have information to share with the members.”
Low-voltage Projects to be Exempted from Competitive Window Process
With two no votes and one abstention, members approved revisions to the Operating Agreement that exempt transmission reliability projects of less than 200 kV from the competitive proposal windows. The revisions include a friendly amendment making explicit stakeholders’ right to submit comments for PJM’s consideration.
Such projects are almost always assigned to incumbent developers, and PJM said the change would enable its engineers to focus on problems more likely to result in a competitive greenfield project. (See “Voltage Threshold will Exempt Some Projects from Proposal Window,” PJM Planning Committee and TEAC Briefs.)
Sharon Segner of LS Power reiterated her concern. “Our view is Order 1000 very clearly said that when projects have regional cost allocation, there needs to be a competitive window associated with them.”
Brenda Prokop of ITC Holdings, who abstained, voiced similar concern.
But, she said, “We know PJM will implement a number of screenings to ensure that those projects that qualify for a competitive window will continue to qualify. We do have those implementation concerns.”
Long-term Firm Transmission, PAR Manual Changes Endorsed
Members unanimously approved proposed manual changes that modify long-term firm transmission service methods.
Revisions to Manual 14A: Generation and Transmission Interconnection Process add a cost allocation obligation for new service requesters to fund facility upgrades.
Changes to 14B: PJM Regional Transmission Planning Process describe the baseline and new service request studies; the distribution factor and rating limit allowed to contribute to flowgates; and the interaction of baseline and new service request studies on constraints identified in the capacity import limit studies.
Separate changes to Manual 14A were endorsed with two abstentions. They make clear that phase angle regulator (PAR) technology is eligible for transmission injection rights. (See “Phase Angle Regulators Qualify for Transmission Rights,” PJM Planning Committee and TEAC Briefs.)
Manual Changes Approved
The MRC on Thursday unanimously endorsed the following manual changes:
Manual 27: Open Access Transmission Tariff Accounting. Changes allow for network service peak load values submitted by electric distribution companies to be scaled by the eRPM auction software if they do not add up to the annual network service peak load allocation for the area.
Manual 38: Operations Planning. Changes resulting from annual review correct typos, revise terms for consistency and update PJM reliability study procedures.
Manual 40: Training and Certification Requirements. Implements a new process requiring operators and dispatchers not in compliance be removed from their shifts. Also establishes a compliance score scheme that will trigger a violation notice to the company and potentially FERC. (See “New Operator Compliance Rules to Take Effect Feb. 1,” PJM Operating Committee Briefs.)
Members Committee
PJM Files Conforming Cost Cap Tariff Changes with FERC
With one abstention, members approved Tariff and Operating Agreement changes conforming to FERC’s order that revisions to the energy market offer cap exclude the 10% adder from cost-based offers more than $2,000.
PJM filed the changes with FERC on Friday, requesting an effective date of March 29 (ER16-814).
The new cap is likely to be only temporary. FERC last month issued a Notice of Proposed Rulemaking that would cap all generators’ incremental energy offers at the higher of $1,000/MWh or an RTO-verified cost-based offer. (See FERC Proposes Uniform Offer Cap Across RTOs.)
LC Charter Change Allows Leeway to Cancel Meetings
Members endorsed changes to the Liaison Committee charter.
The revisions provide for an LC meeting with the board or the second General Session meeting in a calendar year to be canceled upon a super-majority vote of the sector whips. The Members Committee would need to receive three business days’ notice of such a vote. Any sector voting not to cancel a meeting would be required to provide at least one topic to be discussed.
Xcel Energy last week reported net income of $984.5 million in 2015, a 3.6% decrease from $1.02 billion in 2014, as lagging sales and “negative” weather led to a decrease in revenue. The company brought in about $11 billion in 2015, compared to $11.7 billion in 2014.
In a year-end earnings call on Thursday, CFO Teresa Madden said that sales to both industrial and residential customers fell despite healthy economies in the company’s service territories. While electricity sales were only slightly less than in 2014, natural gas revenue fell by 21% due to milder weather in the summer and winter.
Xcel officials focused on its reported earnings per share, $2.09, a 3% increase over its 2014 EPS of $2.03. Xcel had given an earnings guidance of $2.05 to $2.15 after it posted its third-quarter results. This was the 11th consecutive year the company met or exceeded its earnings guidance, Xcel said.
“I am pleased with our 2015 results,” CEO Ben Fowke said. “We delivered earnings within our guidance range despite negative weather and certain regulatory challenges.”
The $2.09 EPS excluded a $79 million charge ($0.15/share) from cost overruns on the upgrade of its Monticello nuclear plant.
The decrease in revenue was partially offset by reduced natural gas costs and operations and maintenance expenses, as Xcel improved efficiency at its nuclear plants.
Madden reaffirmed the company’s earnings guidance of $2.12 to $2.27 per share for 2016.
Earlier this month, Xcel reported an increase in fourth-quarter earnings, with net income of $209 million ($0.41/share) in 2015 compared with $196.3 million ($0.39/share) in 2014, a 6.5% increase. Revenue for this quarter was also down from the previous quarter, but the decrease in expenses more than made up the difference.
Xcel said rate increases in several jurisdictions helped 2015 earnings. In December, however, Texas regulators rejected the company’s request for a $42 million increase, instead ordering a decrease of $4 million effective this month.
FERC has dismissed NRG Power Marketing’s complaint alleging MISO’s 2013 revision of congestion pricing rendered the company’s financial transmission rights worthless (EL16-3).
The commission on Monday found NRG’s contentions “baseless.” It said the company would not have bid differently into a late 2013 FTR auction even if it were made aware of the change to MISO South’s commercial pricing nodes — revised as part of the region’s integration — ahead of time. The commission relied on MISO’s reporting that NRG entered the same number of megawatts into the auction as it did in the RTO’s later annual auction revenue rights nomination.
“That NRG’s nominations in the partial-year financial transmission right auction allocation were identical to the total number of megawatts for which it made nominations in the ensuing annual auction revenue rights nomination, as MISO states, undermines NRG’s claim that it would have bid differently … had it anticipated MISO’s actions,” FERC wrote.
NRG filed its complaint last October, claiming MISO told market participants it was consolidating commercial pricing nodes in MISO South into a single node only after it closed the bid window for the FTR auction.
NRG said this “effectively nullified the results of those FTR auctions and rendered the FTRs purchased by NRG through those auctions valueless,” according to FERC. The action, NRG argued, also nullified the results of the annual 2013 auction and October 2013 multi-period monthly auction.
MISO denied the allegations, arguing NRG failed to produce any evidence of unhedged congestion costs.
FERC said the consolidation wasn’t in violation of the MISO Tariff, and that the RTO provided adequate notice to market participants via a working group. NRG representatives participated in four stakeholder meetings on the topic ahead of the change, and FERC said a complaint should have been filed earlier.
The commission also noted that it was clear that FTRs would be valued differently in the integrated MISO South. “It is evident that pre-integration, FTRs with both sources and sinks in what would become MISO South are fundamentally different products, with different potential values, than post-integration FTRs with both sources and sinks in MISO South. NRG purchased the former but now seeks to be compensated for the potential value of the latter in the post-integration world,” FERC said.
AUSTIN, Texas — ERCOT will send state regulators a white paper that outlines potential revisions to its operating reserve demand curve (ORDC) but makes no recommendations because of a lack of consensus on the need for changes.
The Technical Advisory Committee unanimously endorsed the white paper Thursday as “responsive” to questions Public Utility Commissioner Ken Anderson raised regarding the ORDC’s performance last summer.
In a memo to his two fellow commissioners in October, Anderson called for a PUCT review of the methodology behind the ORDC, a price adder intended to reflect the value of reserves.
ERCOT instituted the ORDC in June 2014 in response to a PUCT order. Energy and reserves were previously priced separately, and ERCOT could show low energy prices during a reserve shortage, creating reliability concerns.
‘Unexpected’ Results
Anderson said the ORDC was an improvement. During late summer, however, he said it produced “unexpected” results, citing Aug. 13, when he said “the ORDC adder did not seem to reflect appropriately” a reduction in physical responsive capacity (PRC) — online generation able to quickly respond to system disturbances.
ERCOT operators can take out-of-market actions, such as calling Energy Emergency Alerts (EEA), when PRC drops too low. On Aug. 13, operators deployed non-spinning reserve service (NSRS) as the PRC dropped to 2,371 MW. However, real-time online reserve capacity (RTOLCAP) was 3,629 MW and wholesale prices reflected that availability.
Anderson’s memo — known as “the Aug. 13 memo” — questioned whether the inputs used to calculate the loss-of-load probability should be reevaluated. “I ask the question because at certain hours of certain days last summer the price adder resulting from the ORDC seem to suggest [a loss-of-load probability] of well under 1%, even though ERCOT was considering making conservation appeals.”
Some stakeholders quoted in the white paper cited Anderson’s observation, saying the incident demonstrated that the ORDC “is not aligned with operations.”
Other stakeholders said that the ORDC is performing as intended. “There was sufficient additional offline generating capacity not counted in PRC available to the system during the 8/13/15 event, so it was appropriate for ORDC to recognize a low loss-of-load probability,” the white paper said.
The Aug. 13 incident came just three days after ERCOT set a new peak demand of 69,877 MW.
ERCOT staff said the initial assumption was that the behavior was related to ORDC. However, it has since determined the event is related to how available reserves are counted.
Coordinated Review
Anderson suggested PUCT staff coordinate their work with ERCOT’s in reviewing ORDC parameters. That includes the 2,000-MW threshold for operating reserves and whether they should be more closely correlated with the PRC, the value of lost load (currently $9,000/MWh), the calculations that go into the ORDC’s loss-of-load probability curve and other data inputs.
ERCOT’s Supply Analysis Working Group developed the 14-page white paper to address each of Anderson’s bullet points and provide more informed discussion on his request. It collects stakeholder recommendations and staff analysis, but the paper “is not intended to address any threshold issues such as what an appropriate reserve margin is for the ERCOT region or how it should be attained,” it said.
The paper also was endorsed by ERCOT’s Wholesale Market Subcommittee, though it was careful to note the endorsement “does not reflect any unanimous recommendations by either WMS or SAWG.”
SAWG stakeholders did agree that operators should not be given additional discretion in calling an EEA and that the “effective price cap” should remain at $9,000/MWh.
TAC Chair Randa Stephenson, of the Lower Colorado River Authority, praised the working group for its “Herculean effort in a short amount of time” before making it clear to the committee what it was endorsing.
“We’re not endorsing the white paper, because there are lots of ideas but little discussion. But we’re endorsing the white paper as being responsive to Commissioner Anderson,” said Stephenson, newly re-elected as the TAC’s chair.
ERCOT staff will file the white paper while staff, stakeholders and PUCT staff continue their ORDC review.
ERCOT Explains Delay in CRR Auction Results
On another matter, ERCOT staff explained a recent three-day delay in posting the results of February’s monthly congestion revenue rights (CRR) auction as a result of “new, unidentified software behavior that was not compatible with our procedures.” Staff said the error was not identified until CRR systems attempted to transfer auction transactions to the settlements systems and pre-assigned CRRs were not priced in the auction.
Market participants were notified the CRR auction was invalid 6 ½ hours after the incorrect results were initially posted Jan. 14. Updated results were posted almost 72 hours later, on Jan. 17.
Staff told the TAC the issue can be resolved with process changes.
Protocol Revision Requests OK’d
The TAC also unanimously approved eight protocol revision requests, ranging from aligning protocols with NERC reliability standards to reactive-power testing requirements:
NPRR691, Alignment of Protocols with NERC Reliability Standard BAL-001-TRE-1;
NPRR713, Reactive Power Testing Requirements;
NPRR720, Update to Settlement Stability Reporting Requirements;
NPRR734, Digital Attestation Signature Authority Expansion;
NPRR739, Prohibiting Load Resources in Participating as Dynamically Scheduled Resources;
NPRR740, Retail Clarification and Cleanup;
NPRR742, CRR Balancing Account Invoice Data Cuts; and
NPRR743, Revision to MCE to Have a Floor for Load Exposure.
MISO told FERC last week that it needs to adjust the formulas in its calculation of capacity import limits to avoid reliability problems.
The RTO made its case in a request for clarification Friday in response to FERC’s Dec. 31 order to change the way it conducts capacity auctions (EL15-70, et al.).
FERC said MISO’s $155.79/MW-day maximum bid was too high and that its approach to determining capacity import limits doesn’t take into account counter-flows. (See FERC Orders MISO to Change Auction Rules.)
MISO addressed the maximum bid issue in a compliance filing in which it submitted rule changes to set the initial reference level — part of the calculation of the opportunity cost of exporting capacity to PJM — to $0/MW-day. But it said it needs two adjustments to FERC’s order regarding its treatment of capacity imports.
Illinois Attorney General Lisa Madigan and the Illinois Industrial Energy Consumers also filed a clarification and rehearing request Friday.
New Year’s Eve Order
FERC’s New Year’s Eve order found that MISO’s calculation of local clearing requirements is unjust and unreasonable “because it could underestimate the impact that counter-flows from capacity exports have on the capacity import limit.”
The commission ordered MISO to adopt the Independent Market Monitor’s recommendation that adds back the amount of capacity exports included in base power transfer to eliminate the negative impact that capacity exports have on the calculation of the capacity import limits.
However, MISO said that two adjustments need to be made to comply with the order and maintain reliability.
First, the RTO proposes to remove the impacts of exports from the capacity import limit calculation. “If the full value of the exports must be realized exclusively through revisions to the capacity import limit, the capacity import limit calculation may overstate system capabilities, thereby causing a reliability problem,” MISO wrote.
MISO also asked to subtract the amount of exports from non-pseudo-tied resources from the local clearing requirement. In prepared testimony, Laura Rauch, MISO’s manager of resource adequacy coordination, said pseudo-tied units cannot be relied on because their “output is not directly available to the MISO region to relieve a constraint or in the case of an emergency.”
MISO said FERC should “recognize the benefits exports can make in terms of satisfying local resource requirements.” Rauch said that non-pseudo-tied resources that export their power outside of MISO can still meet local resource needs if needed during peak loads because MISO retains dispatch control over the resources. Rauch said the compromise would “accurately remove the impacts of exports from the capacity import limit calculations while acknowledging the support that these units may provide for their local resource zones.”
MISO’s position was supported by an affidavit from Market Monitor David Patton.
Should FERC refuse to clarify or grant rehearing, MISO asked the commission to allow it to employ its revised calculations to the 2016-2017 Planning Reserve Auction without an auction results resettlement. The auction is scheduled for April 1.
Illinois Wants ‘Going-Forward’ Costs Cleared Up
The IIEC and Madigan also sought clarification or rehearing on the Dec. 31 order, worried that “going-forward costs” could be interpreted to include sunk costs.
“The commission should clarify that the going-forward costs used to calculate facility-specific reference levels may include only prospective fixed costs that would be avoided by shutting down the facility during the forthcoming MISO planning year… The plain language of the term ‘going-forward costs’ implies that the only costs that may be included are costs that have not yet been incurred,” the two parties wrote in a joint filing.
The Illinois parties are also asking that FERC explain “the procedure to be employed by the Independent Market Monitor for calculating lost opportunity costs in establishing facility-specific reference levels.”
MISO Chief Operating Officer Richard Doying said during a Jan. 26 Markets Committee of the Board of Directors meeting that MISO will make a second compliance filing by March 30. To increase capacity supply and lower prices in the future, FERC gave MISO 90 days to develop default, technology-specific avoidable costs in time for the 2017/18 capacity auction.
In addition to FERC-ordered changes, MISO’s creation of a two-season capacity market could be filed by spring and help alleviate pricing concerns associated with the 2017/18 auction, Doying said. (See MISO Proposes Two-Season Capacity Market.) Doying said he would have more details on MISO’s response to PRA changes in June, after filings are made.
FERC last week denied American Electric Power’s request for a waiver of nonperformance penalties under PJM’s Capacity Performance construct for delivery year 2019/20.
AEP filed the request in November on behalf of four of its vertically integrated utilities that traditionally participate in PJM’s capacity market as fixed resource requirement entities rather than in the Reliability Pricing Model: Appalachian Power, Kentucky Power, Wheeling Power and Indiana Michigan Power. The company argued that the waiver would make it easier for its utilities to decide whether to remain FRR entities by the March 7 deadline.
“To be clear, if AEP makes the election to remain an FRR entity for the 2019/2020 delivery year … it will comply with the CP rules applicable to FRR entities, including submitting a capacity plan comprised of 80% Capacity Performance qualifying resources,” AEP said. “AEP seeks, simply for the sake of making that election in March 2016, a limited waiver of sections of the Tariff and [Reliability Assurance Agreement] imposing heightened nonperformance charges on FRR entities beginning in the 2019/2020 delivery year.”
AEP pointed to numerous factors making the decision more difficult:
Capacity Performance has not yet been implemented, and neither PJM nor market participants have any experience with the new rules. (Delivery year 2016/17, the first to include Capacity Performance resources, begins June 1.)
States in its service territories have yet to file compliance plans in response to EPA’s Clean Power Plan and EPA has not finalized its federal implementation plan, which would be imposed on states that do not file their own plans.
Several cases before the U.S. Supreme Court regarding federal vs. state jurisdiction over market resources, including demand response. (The court has since ruled on the question of DR, reversing a lower court’s decision voiding FERC’s jurisdiction over DR resources. See Supreme Court Upholds FERC Jurisdiction over Demand Response.)
Last year, the commission approved PJM’s Capacity Performance proposal, including the provision that FRR entities would be subject to the same nonperformance penalties as those participating in the auctions. Under the new construct, the resources in FRR entities’ capacity plans must be at least 80% Capacity Performance. The decision to include FRR entities was opposed by state regulators, who saw it as infringing on state jurisdiction by effectively eliminating states’ choice to opt out of the capacity auction process. (See FERC OKs PJM Capacity Performance: What You Need to Know.)
FERC was not convinced. The uncertainties faced by AEP are not unique to the company, the commission said. It suggested that AEP’s utilities should simply elect to remain as FRR entities for now and reconsider its decision next year after gaining experience under Capacity Performance. “We disagree that AEP’s election requirements are different from other similarly situated resources deciding whether to select the fixed resource requirement alternative or to participate in PJM’s RPM capacity auction,” FERC said.
The commission was also unpersuaded by AEP’s claim that the waiver would not harm any other market participants. Granting the waiver would not be fair to other FRR entities who did face nonperformance penalties, FERC said.
AEP’s request was opposed by PJM, the Independent Market Monitor for PJM, the PJM Power Providers Group and the Electric Power Supply Association. The Indiana Utility Regulatory Commission supported the waiver, arguing that RPM participants had more flexibility than FRR entities, as the former are able to buy out of their future capacity positions in the RTO’s three Incremental Auctions.
The Base Residual Auction for delivery year 2019/20 is scheduled for May 11 to 17.
OKLAHOMA CITY — SPP completed its first international transaction late last year, thanks to Canadian interconnections that came with the Integrated System’s addition to the RTO last year.
SPP Executive Vice President and COO Carl Monroe told the Regional State Committee last week that SaskPower, the principal electric utility in Saskatchewan, came to the RTO’s aid during a mid-December “emergency situation” in North Dakota. Monroe said SaskPower was able to “facilitate power” during a storm and after some transmission outages via existing interconnections in the state.
The RTO would not divulge additional details, claiming market sensitivities.
SPP’s Bruce Rew updates the RSC.
Bruce Rew, vice president of operations for SPP, told the committee the Integrated System also has helped with market-to-market congestion between the RTO and MISO.
The system “is very integrated with MISO in the upper Midwest,” Rew said. “The market solutions with IS seem to be working very well for us.”
SPP CEO Nick Brown thanked the committee for “being instrumental in helping us engage with your states” as the grid operator prepares to help its region comply with EPA’s Clean Power Plan.
“We, as SPP staff, have been asked to assess the impacts of implementation,” Brown reminded the committee. “We do continue to urge regional approaches over state-by-state approaches … but the biggest challenge for us is we don’t know what to plan for yet.”
Last week’s quarterly RSC meeting was the first led by Patrick Lyons, chairman of the New Mexico Public Regulation Commission. Lyons welcomed Nebraska Power Review Board member Dennis Grennan as the committee’s 10th and newest member.
A joint FERC-NERC review of nine unnamed utilities’ system restoration and recovery plans found them “for the most part … thorough and highly detailed” but also identified room for improvement and called for additional studies.
“The reviewed plans require identification and testing of black start resources, identification of primary and alternate cranking paths, and periodic training and drilling on the restoration process under a variety of outage scenarios,” the report said. “Likewise, the joint staff review team found that participants had extensive cyber security incident response and recovery plans for critical cyber assets covering the majority of the response and recovery stages.”
Staff from FERC, NERC and Regional Entities gathered information from “a representative sample of nine registered entities with significant bulk power grid responsibilities, including some entities that are registered with NERC in multiple functions.” The report emphasized that the staff review “was not a compliance or enforcement initiative.”
The report identified several opportunities for improving readiness through measures including improving the clarity of some NERC reliability standards.
It also took note of best practices used by some participants that went beyond NERC requirements, such as the inclusion of illustrations and step-by-step procedures in restoration plans and conducting drills that involve the actual transfer of control center operations to an alternate site. “The actual evacuation and verification of functionality of recovery resources can reveal unknown issues or problems through use of the alternate site’s cyber assets,” it said.
Recommended changes included:
Clarification on when system changes will trigger a requirement to update restoration plans. “In considering these measures, the kinds of events that may warrant an update to the system restoration plan should be identified, taking into account the length of time the system is affected, as well as the overall objective of ensuring that restoration plans are generally flexible enough so that system modifications can be addressed without continuous updates.”
Exercises and drills testing the transition from transmission operator island control to balancing authority area control error and automatic generation control.
Cyber security incident response plans and recovery plans for critical cyber assets should designate accountability at the cyber asset level (e.g., energy management system (EMS) servers, remote terminal unit concentrators, network routers).
More detail on the types of cyber security events that should trigger a response and reports. “While the team recognizes that [Critical Infrastructure Protection] version 5 will require responsible entities to have processes to identify cyber security incidents, consideration should be given as to whether any additional clarification or improvements are needed once some experience is gained with CIP version 5,” which takes effect for some assets on April 1.
Expanding the use of cyber security technical expertise and advanced technical tools.
Reducing the risk of recovery plan “inventory assumptions.” It said “entities may assume that hardware from external sources or other third-party vendor support needed for recovery of critical cyber assets will be available, without necessarily having measures to ensure availability. Likewise, entities may not consider interdependent or common-mode failure scenarios, which can create the need to recover multiple critical cyber assets concurrently from the same vendors.”
Among the studies recommended were:
Assessing system restoration steps that may be difficult if operators lose supervisory control and data acquisition computer systems, inter-control center communications protocol or EMS functions.
Identifying factors to be considered for replacing black start resources, including locational diversity and dual-fuel capability.
Determining the benefits of including existing or future voltage source converter DC lines in restoration plans.
