Following a directive from a federal appeals court, FERC ordered ISO-NE to provide more information proving that the 2013-14 winter reliability program resulted in just and reasonable rates (ER13-2266).
“ISO-NE should request from program participants information that will enable ISO-NE’s [Internal Market Monitor] to evaluate the competitiveness of the program and whether any amounts exceeding a participant’s cost of providing the winter reliability service are indicative of market participants exercising market power in that program,” FERC wrote in the Aug. 8 order.
ISO-NE previously said such information was commercially sensitive and should not be disclosed.
Under the program, selected resources were compensated through a monthly payment derived from the resources’ bids under an “as-bid” pricing mechanism, rather than a uniform clearing price, FERC wrote.
The program paid for demand response resources and some of the carrying costs for dual-fuel generators that stored oil on-site.
FERC granted ISO-NE expedited approval for the program in late 2013 due to concerns that the region might fall short of generation due to the retirement of coal-fired units and tight natural gas supplies.
Although ISO-NE estimated the program would cost no more than $43 million for up to 2.4 million MWh of energy, the RTO filed for approval of bids totaling nearly 2 million MWh at a cost of $78.8 million, which FERC accepted.
TransCanada Power Marketing argued that this cost disparity required more scrutiny and that the commission did not have adequate information to determine whether the bid results were just and reasonable.
After FERC denied a request for rehearing in 2014, the company appealed to the D.C. Circuit Court of Appeals. On Dec. 22, 2015, “the court agreed with TransCanada’s argument that the record was devoid of any evidence regarding how much of the program’s cost was attributable to profit and risk mark-up,” according to the commission order.
The order directs ISO-NE to request from market participants the basis for their bids, including the process used to formulate the bids. The commission also required an analysis from the IMM and a recommendation from ISO-NE on the reasonableness of the bids within 120 days.
FERC also said ISO-NE “may choose to request” information justifying suppliers’ bids in in the subsequent years’ reliability programs.
MISO will ask FERC to end a system support resource agreement in Michigan’s Upper Peninsula, saying its reliability concerns will be addressed by American Transmission Co.’s transmission reconfiguration until an upgrade expected in service by the end of 2020.
MISO said ATC’s proposal to open transmission circuits and split the western UP load pocket into two radially-fed areas “avoids [the] risk of cascading loss of load during prior outages,” allowing the termination of White Pine Unit 1’s System Support Resource (SSR) agreement.
MISO plans to file to terminate the SSR agreement following a 90-day notice, Joe Reddoch of MISO’s System Support Resource Planning Group said during a meeting of the West Technical Study Task Force Aug. 8.
Reddoch said that the two-radial configuration would be used only during planned outages or when one of the area’s two 138kV lines is unexpectedly out of service. The load pocket would be served by the remaining 138-kV line and the Conover 69-kV line.
“Some of these are day-long outages. I think the longest one we looked at is somewhere in the order of a week,” Reddoch said.
MISO concluded the two-radial configuration would result in only a small increase in the risk of loss of load.
The load pocket in the western Upper Peninsula around White Pine — about 68 MW during shoulder periods and 80 MW in the summer — is supported by two 138-kV circuits and one 69-kV line. An outage of one 138-kV line followed by the loss of the second line “results in severe overloads and voltage collapse in the local load pocket,” MISO said.
The RTO said ATC’s plan would result in a “limited” increase in the risk of a consequential load shed, which could be managed within the RTO’s planning and operating criteria, which allows mitigation through reconfiguration.
“From our perspective, this is an acceptable alternative,” Reddoch said. “The radial reconfiguration isn’t unheard of in the system. It may not be ideal, but it’s certainly acceptable.”
Richard Bonnifield, an attorney for White Pine Electric Power, said stakeholders were being “blindsided” by the introduction and acceptance of ATC’s plan in the same stakeholder meeting and asked for a reliability impact analysis on the removal of White Pine. Reddoch said a reliability analysis would not provide any additional information and would serve only to “unnecessarily” delay implementing the solution.
Bonnifield fired back that the stakeholder process regarding the SSR removal was “unstructured.” Other stakeholders asked for more time to assess the alternative.
“Our assessment does not require any extensive analysis. This reconfiguration is already in place for unplanned outages. This has already been an accepted process for unplanned conditions. I don’t think we can conclude that it’s not acceptable,” Reddoch said. Ken Copp, a strategic technical advisor with ATC, confirmed that ATC’s system in the western Upper Peninsula would return to a configuration prior to the 1990s when Wisconsin Electric Power Co. and ATC tied their lines together.
Some stakeholders asked Copp why the lines were tied together in the first place.
“Back in that day, contract paths were a big deal, especially for wholesale customers. It achieved some contract path goals, but we have to label that as anecdotal, not something that’s documented,” Copp said.
Some stakeholders said the transmission reconfiguration would not be as reliable as keeping the SSR in place.
Reddoch responded that the plan isn’t in violation of planning criteria and presents a no-cost alternative for ratepayers. “It might not be ideal, but even an SSR isn’t ideal,” he said.
White Pine Electric Power requested retirement of White Pine Unit 1 in April 2014. The current SSR agreement was expected to last until 2017.
The long-term solution for the reliability concerns that gave rise to the SSR is a $100 million plan to convert the 75-mile, 69-kV transmission path from Lakota Road to Mass to Winona to 138 kV. The project, included in MISO’s 2015 Transmission Expansion Plan, is slated to be finished in December 2020.
Angela Castle of the Michigan Agency for Energy said ATC’s solution would be “much less onerous” on ratepayers.
Steve Leovy, a transmission engineer at WPPI Energy, told stakeholders that ATC presented the alternative solution despite not being directly affected by SSR costs.
“ATC isn’t in this; they don’t have to pay the SSR costs. Our ratepayers have to pay the SSR costs. We are supportive of this … and we don’t take the increased risk of load loss lightly,” Leovy said.
Reddoch said MISO will work with ATC in the coming weeks to revise the company’s operating guide to remove White Pine availability and introduce the reconfiguration plan. Details of the revised operating guide will be kept confidential per MISO procedure.
ERCOT has broken the 70,000-MW barrier for the first time, setting six new systemwide hourly peak demand records this week.
The Texas grid operator registered its latest record peaks Thursday when system load reached 71,197 MW between 4 and 5 p.m., after having climbed to 71,043 MW between 3 and 4 p.m.
That smashed records set Wednesday (70,572 MW) and Monday (70,169 MW), which had bettered the previous mark of 69,877 MW set last August. The grid fell short of another record Friday, peaking in the 4 p.m. hour at 70,343 MW.
Real-time settlement prices spiked to $220.37/MWh systemwide at 2:15 p.m. Thursday. The Rayburn load zone was still settling at $228.72 at 4 p.m., with the Whitetail Wind Project in the congested North zone offered into the market at as much as $1,000.14 during the 4 p.m. hour.
ERCOT’s peak demand first surpassed 70,000 MW between 3 and 4 p.m. Monday, before setting a short-lived record between 4 and 5 p.m.
With triple-digit temperatures settling over the state, the Texas grid operator expected load to peak above 70,000 MW again Thursday between 4 and 6 p.m. Whether it sets a new record remains to be seen.
“Welcome to August,” ERCOT CEO Bill Magness told the Board of Directors Tuesday morning. “Usually, peak records set in August don’t normally last.”
Magness was quick to note ERCOT did not have to call an emergency alert Monday, saying, “It was a great performance by the system and the people who make it work.”
“These hot summer days always put our grid to the test,” said ERCOT’s director of system operations, Dan Woodfin, on Wednesday. “We have had sufficient generation available to carry us through these high-demand periods.”
ERCOT staff said it expects operating reserves to drop below 3,000 MW this week. Its final summer Seasonal Assessment of Resource Adequacy said the ISO had 78,434 MW of generation capacity available and projected a peak summer demand of 70,588 MW.
The Texas grid operator also set a new weekend peak demand record Sunday when it hit 67,000 MW.
Staff said it expects consumption to drop next week and believes it has sufficient generation as long as resources are available. ERCOT’s final summer Seasonal Assessment of Resource Adequacy said the ISO had 78,434 MW of generation capacity available and projected a peak summer demand of 70,588 MW.
The PJM Board of Managers has approved more than $636 million in transmission investments, including a $320 million market efficiency project — the RTO’s largest ever — designed to ease congestion at the AP South interface.
That project alone is predicted to save customers $622 million over 15 years, PJM said.
Project 9A (without capacitors) is expected to alleviate congestion across Pennsylvania’s border with Maryland and is set to go online in 2020.
The plan, which evolved from the RTO’s Order 1000 competitive process for transmission improvements, involves substation upgrades, two new substations, two new transmission lines and improvements to current lines.
“This is PJM’s largest-ever market efficiency project, and we expect it will resolve a significant amount of the remaining transmission congestion in the eastern portion of PJM,” said CEO Andy Ott.
The principal developers are FirstEnergy’s Allegheny Power, Exelon’s Baltimore Gas and Electric and Transource Energy, an American Electric Power affiliate.
The board also approved $316.3 million in other new or amended projects to maintain reliability.
PJM’s selection of the AP South project was criticized by some stakeholders who argued that planners should further study competing proposals ranging from $72 million to $253 million. (See “Planners to Recommend $340.6M Solution to Congestion in AP South,” PJM Planning Committee and TEAC Briefs.)
Among the detractors was Linden VFT, which wrote a July 29 letter to the board saying, “Despite similar benefits per dollar of cost, PJM has chosen the larger project which purports to produce higher benefits on an absolute basis because of its size. However, PJM gave no indication that it had considered in its recommendation the value of the cost-cap guarantee proposed by” LS Power’s Northeast Transmission Development.
It warned that if cost containment is not valued, it will cease being offered.
“Linden VFT agrees that determining the relative importance of a cost cap over other factors will require PJM to make value judgments, but PJM’s role in project selection requires it to either consider all of the issues in a deliberate fashion (not just those which are easiest to compute) or punt, and effectuate the same value judgments, but by default, without thoughtful consideration.”
The board also received a letter from AEP and Transource lauding the selection process.
Since the Regional Transmission Expansion Plan began in 2000, PJM has greenlit $29 billion in new development and upgrades.
California Gov. Jerry Brown on Monday postponed CAISO’s effort to expand into a Western RTO, saying he wants state agencies to take more time to develop a proposal.
“While very significant progress has been made by the ISO on a transition proposal that meets the criteria in SB 350, there remain some important unresolved questions that would be difficult to answer in the remainder of this legislative session,” Brown said in a letter to legislators.
Passed last year, SB 350 increased California’s renewable portfolio standard to 50% by 2030 while also directing the ISO to explore how its expansion into the wider West could help the state meet that goal.
In response, the ISO commissioned a series of studies investigating the economic, environmental and reliability benefits of regionalization. (See Study Touts Benefits of CAISO Expansion.) CAISO staff also quickly drew up a proposed set of principles for governing an expanded ISO, a task made more urgent by PacifiCorp’s intention to join in 2019. The utility will need to gain approval from regulators in the five Western states in which it operates.
After the original governance plan received a cool reception from many Western industry participants for its “California-centric” nature, the ISO issued a revision to more favorable — if still wary — reviews. (See Revised Western Governance Plan Highlights State Authority.)
“Regionalization is one of the largest issues facing the ISO in its history,” said Carolyn Kehrein, principal consultant for the Energy Users Forum, which represents large energy customers in California. “Unfortunately, the changes [to the original proposal] were made to meet a quick turnaround.”
Others worried that the revised principles — which eliminated a provision for accounting for greenhouse gas emissions from all generators in an expanded ISO footprint — could compromise the state’s efforts to sharply reduce carbon emissions.
Brown was expected to present the governance plan to lawmakers early this month. The governor said he put off that action in order to allow state agencies to develop a “strong proposal” that the legislature can consider early next year.
“The ISO is pleased with the governor’s and legislature’s continued commitment in establishing a regional electricity grid,” CAISO CEO Steve Berberich said in a statement. He pledged to work with stakeholders “to further refine our governance proposal and any other remaining issues to ensure that all parties have ample time to fully evaluate the impacts of a Western grid.”
CARMEL, Ind. — After a missed July filing target and subsequent weeks of hints, MISO on Monday confirmed that it was postponing its forward capacity auction proposal until the 2018/19 planning year.
Richard Doying, MISO executive vice president of operations and corporate services, told the Markets Committee of the Board of Directors that the RTO plans to file the proposal with FERC in early November while using September and October for continued analysis with The Brattle Group.
“I’m glad we’re going to take more time. We need the community along with us,” MISO board member Jennifer Curran said.
Resource Adequacy Subcommittee Chairman Gary Mathis said stakeholders “greatly appreciate the additional time.” MISO had released the draft Tariff language and business rules at a RASC meeting last week.
IMM Wants Board Intervention
Independent Market Monitor David Patton, whose proposed changes were rejected by MISO staff, said the Board of Directors should intervene to stop the forward auction filing.
“This is the first time we’ve asked this in over a decade since the markets were created,” Patton said. “That doesn’t mean good work hasn’t been done, and I think MISO has worked very hard in the last few months. There’s a tremendous amount that we agree on, most importantly that there is a problem.
“I just haven’t been able to come up with anything that would make this market produce efficient prices” within the voluntary forward construct, Patton added.
Board member Thomas Rainwater said MISO’s plan to take more time to explain the Brattle analysis and hold additional stakeholder meetings was enough to hold off on action. However, the Markets Committee plans to hold an executive session to “evaluate the quality of the decisions being made” and determine whether to proceed with the filing.
Board members said their role isn’t to order MISO staff to adopt specific provisions, but to provide oversight. “We’re not going to adjudicate dueling economists,” Curran said.
Patton said he was concerned that MISO plans to make the forward auction voluntary, unlike those in PJM and ISO-NE, which are mandatory.
He also repeated his concern that the proposed auction’s prices will be “highly volatile.” He said demand needs to reflect reliability requirements, and current merchant demand doesn’t include planning reserve margins. (See MISO Backs Forward Auction Plan, Rejects Prompt Proposals.)
The board expressed concerns that excess regulated generation entered at the lower prices expected under the vertical demand curve in the prompt Planning Resource Auction will be “dumped” into the forward auction.
Doying said MISO will restrict the suppliers participating in the forward market to address the concern. MISO says it doesn’t plan to enact a minimum offer price rule.
Patton said he did not share the board’s concern. “That’s not dumping, that’s simply desiring to sell capacity and benefit their customers,” he said.
Rainwater wondered if Patton was paying too much attention to economics and not factoring in electricity subsidies and public policy: “the reality of the markets versus the theoretically perfect market structure.”
Patton said that in private conversations, Brattle staff shared his price signal concerns. He also said Brattle made no attempt to model forward auction participation trends, but it is “nearly unknowable.”
“It wasn’t a very satisfying reliability analysis,” Patton said.
Doying said MISO’s proposal is similar to other FERC-approved designs except for the smaller scale of the affected areas. He also told the board that the forward auction is intended to produce an efficient price, not send strong investment signals.
Meanwhile, Brattle analyst Sam Newell took aim at the hybrid prompt proposal, saying it would create price discrimination between merchant and non-merchant suppliers. He said when a utility has extra capacity to sell, mandating that the price be raised “much higher” for merchant suppliers is “clear economic waste.”
He added that “indisputable economic discrepancy” exists in the hybrid prompt proposal: a two-stage prompt auction with separate clearing prices for retail choice and regulated load.
The board also asked MISO officials about the stakeholder process over the 18 months of negotiations on a new auction design.
“Given that the issue is targeted to retail choice load in Illinois and Michigan, we did start the stakeholder discussions in those areas,” Doying said, adding that once affected stakeholders weighed in, the discussion was brought before the RASC.
Rainwater said he noticed stakeholders were split and asked if the RASC was a public-enough forum for redesign discussion.
“This was a very well attended set of meetings,” Doying replied.
Board member Paul Feldman asked if the state legislatures in either Michigan or Illinois could supersede MISO’s proposed solution. Stakeholders have expressed concerns that state laws could force an entire zone into the forward auction, such as Zone 2, which contains Michigan’s Upper Peninsula. The Michigan Legislature is considering removing its current 10% cap on retail choice and becoming fully regulated.
“We’d need a lawyer to answer that question,” Doying replied. “In that case, there may be a difference between [MISO] ‘choos[ing] to abide by’ and ‘respect[ing] the jurisdiction of.’”
Jeff Bladen, executive director of MISO market services, said at last week’s RASC meeting that MISO will respond to stakeholder questions on the draft Tariff language and business rules; however, a scheduled Aug. 12 conference call was cancelled in light of the filing delay. The thrust of both drafts is to put generators in retail choice states on the “same footing” as utilities in traditional, vertically integrated states.
MISO’s proposal specifies that the full planning reserve margin be procured in the forward auction, instead of fulfilling local clearing requirements as proposed in the first version of the auction redesign.
The RTO is still working to shape a demand curve for the three-year forward auction for retail choice load. A demand curve was not included in the draft Tariff language.
“We are working with The Brattle Group to refine the shape,” Bladen said. “This is the main element that’s outstanding.” Bladen said the RTO is reviewing demand curve parameters it recently received from Brattle’s pricing and reliability analysis.
NRG Energy’s Tia Elliott asked if MISO could still implement the forward auction construct by next year with an October filing. Bladen said the RTO was “unlikely to implement” the revised auction design in 2017 if a filing is made in the fall.
Bladen said some of the Tariff language was inspired by PJM’s three-year forward auction descriptions. “There aren’t very many examples of closely modeled language except in the conceptual sense,” he said.
“This is difficult because there’s very little being presented. It’s hard to understand what’s going on,” Indianapolis Power and Light’s Ted Leffler said, adding that although Tariff language and business rules were issued, MISO did not walk through them in a public forum.
Bladen said Leffler’s assessment of the “dense” Tariff language was “fair enough” and said it is why MISO was considering taking more time before filing.
Jim Dauphinais of the Illinois Industrial Energy Consumers said he was concerned that local resource zones with competitive demand — otherwise required to participate in the forward auction based on a bright line test — will be exempted if the demand’s local requirement is less than 0.5% of the systemwide planning reserve margin requirement.
Arkansas Public Service Commission Chairman Ted Thomas asked if load-serving entities failing to procure capacity in the new model will still be subjected to the capacity deficiency charge of 2.75 times the applicable cost of new entry. Bladen said they would.
Six External Zones
MISO is considering the addition of six external resources zones, Manager of Resource Adequacy Coordination Laura Rauch told the RASC.
Rauch said the RTO used participation from the 2016/17 planning year to create four external resource zones in MISO North and two in MISO South. Rauch said that external resources bordering the RTO and companies with reliability coordination duties not participating in the market would be excluded from the zones.
MISO officials asked for stakeholder suggestions by the end of the month on external resource zone offer price caps. The RTO still does not have a target date on filing its seasonal and locational proposal.
Customized Energy Solutions’ David Sapper asked why external resource zones need a price cap, as external resources are not subject to economic withholding rules. “External resources are not registered with MISO, and it doesn’t seem like you could force them to offer in the first place,” Sapper said.
MISO engineer Akshay Korad said price offer caps could be useful when there’s insufficient supply to clear. Korad said the RTO could set price and offer caps based on the cost of new entry or assign two separate values for the South and North external zones.
Korad said adding external zones will not significantly increase cleared capacity in the auction.
He also said external resources will only clear toward the planning reserve margin requirement in the capacity auction, and that cleared external capacity will count toward sub-regional import and export limits. External zone auction clearing prices would be the same as systemwide clearing prices if sub-regional import/export limits do not bind. Marginal resources could set external clearing prices, Korad said, if a simultaneous feasibility test reduces the external zone’s capacity export limit.
The U.S. Supreme Court cast a long shadow as New York regulators drafted the Clean Energy Standard and its incentives to preserve upstate nuclear power plants.
Audrey Zibelman, chair of the state Public Service Commission, said that the order adopted last week was drafted to avoid legal challenges that could jeopardize the standard’s goal of generating 50% of the state’s power from renewable resources by 2030. PSC lawyers feared challenges to the zero-emission credit (ZEC) program for nuclear plants and the way in which renewable energy development is encouraged. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
Constellation Energy Nuclear Group
The PSC says it believes it avoided the issues that caused the Supreme Court’s April ruling in Hughes v. Talen voiding Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
The court ruled unanimously that the state’s attempt to subsidize generation interfered with FERC’s jurisdiction over wholesale electric markets because it employed a contract-for-differences tied to PJM capacity prices. The court said the contract also violated the Constitution’s Supremacy Clause, which establishes that federal law pre-empts contrary state law.
The court provided state regulators some guidance for crafting their programs in the future, saying it rejected Maryland’s initiative only because it disregards FERC’s wholesale rate.
It was not ruling on “the permissibility of various other measures states might employ to encourage development of new or clean generation, including tax incentives, land grants, direct subsidies, construction of state-owned generation facilities or reregulation of the energy sector,” the court said. “Nothing in this opinion should be read to foreclose Maryland and other states from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation.’”
FERC General Counsel Max Minzner has called the ruling “a very narrow decision” that preserved “a wide range of tools for states.” (See Court’s Reticence Frustrates Energy Bar.)
The PSC order considered various scenarios for procuring renewable energy, including its existing renewable energy credit model, a reliance on long-term power purchase agreements and a hybrid of the two. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.) The order adopted last week relies on the REC-only framework, which New York has used for 12 years to encourage compliance with its renewable portfolio standard.
“One question is our ability as a retail regulator to mandate power purchase agreements in light of the Supreme Court’s recent decision, so we didn’t want to get embroiled in litigation and have that slow up the program and introduce uncertainty,” Zibelman said at a news conference following the order’s adoption.
“The potential for federal pre-emption creates a risk that could slow the implementation of the CES. The [Maryland case] does not directly bar power purchase agreements. It does, however, cast uncertainty over state-mandated contracts that parties may argue interfere with federally supervised wholesale markets,” the PSC order states.
Zibelman said the REC approach also is better for ratepayers. “With longer PPAs, you’re fixing the price upfront, and obviously that’s the value investors see. But … to the extent that the technology costs continue to go down, you’re pushing that risk onto consumers.”
The New York State Energy and Research Development Authority will continue to run competitive auctions for developers selling renewable projects’ environmental attributes — competitions separate from NYISO’s energy and capacity markets.
ZEC Pricing
New York has priced ZECs based on EPA’s social cost of carbon, minus prices for carbon allowances sold under the nine-state Regional Greenhouse Gas Initiative, in which New York participates. Load-serving entities must purchase ZECs, which recognize the carbon-free attribute of nuclear power, proportionate to their annual energy sales.
Although it was designed to be similar to the REC procurement, the ZEC program may face a legal challenge that the mandate would suppress energy and capacity prices.
A group of power generators advanced that argument during the public comment period last month.
The comments were “a dry run driving right at the heart of ZEC,” said David Appelbaum, an attorney for the New York Power Authority. “They’re going to try to derail this. I don’t know if they’re going to be successful.”
The suppliers, 11 power generators and marketers, say the ZEC proposal violates the Federal Power Act and impinges on FERC jurisdiction over wholesale markets. “It conflicts with FERC’s policy that the NYISO’s capacity market provide the necessary price signals to encourage maintenance of existing, and development of new, facilities to meet reliability needs,” the suppliers contend. “But for the artificial price suppression, prospective new generators that may have been economic may forego entry, and existing generators that may have been economic may prematurely retire.”
The PSC order sought to head off this line of attack. The proposal “does not establish wholesale energy or capacity prices; it only establishes pricing for attributes completely outside of the wholesale commodity markets administered by NYISO,” the order states. “To the contrary, it addresses a well recognized externality that otherwise would lead to economic inefficiencies with respect to the costs incurred due to environmental damage, in particular, climate change.”
John Reese, the senior vice president of Eastern Generation, one of the suppliers, told RTO Insider on Monday that no decisions on any appeal have been made.
“We continue to look at all of the options, so we are in the process of deciding what is the best action to take,” he said.
CAISO last week began work on a plan to extend participation in the western Energy Imbalance Market to resources located outside the market’s footprint.
Rothleder
The move comes a month after FERC rejected CAISO’s proposal to indefinitely prohibit EIM participants from implementing economic bidding at the market’s interties until the ISO could develop procedures to manage the practice. (See FERC Order Prods CAISO to Allow EIM Intertie Bidding.)
In its June 30 decision, the commission found the ISO’s open-ended timeframe for producing a bidding solution to be “inappropriate” and directed FERC staff to convene a technical conference to explore the issue.
At an Aug. 4 Regional Issues Forum held at Idaho Power’s headquarters in Boise, CAISO Vice President for Market Quality and Renewable Integration Mark Rothleder floated a set of principles for allowing external resources to bid into the EIM.
Rothleder first laid out what CAISO considers to be the challenges in managing bids at the market’s seams. “It’s important to understand how resources participate in the EIM,” he said.
The EIM requires the ISO to accurately model physical flows across the market for every five- and15-minute interval, Rothleder said. The model factors in variables such as EIM demand, expected output from internal and pseudo-tied resources (including short-term forecasts from renewables); and dynamic import schedules.
“Accurate flow-based modeling means we can do accurate congestion management,” which helps minimize the ISO’s uplift costs, Rothleder said.
Less Granularity
Fifteen-minute scheduling of imports at the EIM’s interties doesn’t provide the same granularity. The ISO doesn’t know the exact source of imports, which “can have an impact when something changes at the source level.”
External participation in the EIM could enable the Northwest’s ample hydroelectric resources to bid into the market. Photo of the Rock Island Spill Source: Chelan County Public Utility District
And Rothleder pointed out the distinction between bidding and scheduling at the EIM’s interties.
Bidding is “an offering into the market. That means the market is determining when [the generation is] dispatched,” he said. “The expectation is that, if it’s dispatched, it delivers.”
Still, even a “generic” — or system — bid at the seams “does not have the same type of accuracy as an internal market bid,” Rothleder said.
“Frankly speaking, if it were up to us, we’d want to know where those [external] sources are coming from and accurately model them,” Rothleder said. “Uplift costs can be significant. We don’t want to extend that inefficiency to the EIM without knowing what we’re doing.”
Fifteen-minute “generic” bids at the seams have another shortcoming. That’s because the EIM dispatches beyond that interval down to the five-minute level, where resources can provide services other than just energy, such as flexible ramping capability to account for uncertainty from renewable output forecasts.
“The point is, generic bidding at a 15-minute level might not be offering all the services we need,” Rothleder said.
Economic intertie bidding poses additional challenges for the market:
Intertie bids are currently not subject to market power mitigation, but mitigation and default energy bids — which reflect a unit’s marginal operating costs — are required by the EIM.
Uncertainties regarding the transmission policy and compensation scheme required to facilitate EIM participation by external resources.
Lack of metering, greenhouse gas accounting, responsiveness monitoring and control of external resources.
The first step in addressing those challenges: stakeholder agreement on the principles underpinning a solution.
“If everyone agrees to discuss the principles, we think we can find a way to extend EIM participation to other areas,” Rothleder said.
Participation Voluntary
He emphasized that any solution must first recognize that participation in the EIM is voluntary — external resources are not subject to a must-offer obligation. Balancing authorities outside the market must retain their ability to dispatch resources, serve load and balance their own areas.
The proposal must also address the transmission requirements for external resources to participate in the market. And while compatibility with the region’s existing system of bilateral trades is considered another key principle, so is compatibility with the EIM’s current process — which would entail the kind of flow-based modeling of resources necessary to manage congestion.
CAISO also wants external resources to be comparable to those already participating in the EIM. That would require those resources having 15-minute scheduling and five-minute dispatch capability, as well as meeting data exchange, settlements and metering requirements in order to verify delivery.
External resource participation must also avoid “undue operational risks, administrative burden and implementation costs” for both source non-EIM balancing authority areas and sink EIM BAAs.
That last principle was a key concern for Brad Albert, general manager of resource management at Arizona Public Service.
“I didn’t sign up to be a market operator; I signed up to be a market participant,” Albert said. “I want to know if this is going to present another burden on us and [if we’ll] be compensated for it. This is something we’re going to pay close attention to.”
‘Free Riders’
Albert also expressed concern about “free riders” on the EIM system but said CAISO had “caught the high-level principles” needed to formulate a proposal.
Clay MacArthur, assistant vice president for power marketing and contracts at Deseret Power, wondered whether “both the positive and negative effect” of intertie bidding could be modeled in the EIM’s current market construct.
“In my mind, it’s volume and frequency,” Rothleder replied. “If there were a large volume of intertie bids, you’re faced with managing it. We feel a lot more comfortable if we have the physical location [of the resource] right. Then we have metering.”
“You’re going to need a significant amount of information from that resource that’s going to get bid,” said Tony Braun, a consultant and member of the EIM transitional committee. “How much would be required?”
“I think the level of information is probably comparable to a participating resource” in the EIM, Rothleder replied. “I don’t see that as a technical hurdle here.” Policy issues are more of a concern, he added.
Kahn
“I don’t see anything that isn’t workable,” said Bob Kahn, executive director of the Northwest & Intermountain Power Producers Coalition, which supports increased regionalization of the western electricity market. “There’s clearly a responsibility for those of us who’d like to effectuate this.”
While FERC’s June ruling leaves open the option for each EIM BAA to develop its own plan for external participation, CAISO is seeking uniformity.
“We thought that this would be something that could be adopted by all EIM entities,” Rothleder said. “That’s why what we’re proposing would be a generic solution.”
AUSTIN, Texas — In a meeting with Carol Biedrzycki, you will know two things without question:
If she isn’t talking, she has nothing to say.
If she is talking, she will not stop until she has nothing else to say.
Candor and steadfastness are qualities that Biedrzycki, the consumer advocate in charge of Texas Ratepayers Organization to Save Energy (ROSE), developed over 24 years of engagement with the electricity industry. They’ve made “Carol B” a “storied figure” in state industry regulatory circles, said Ned Ross, who oversees government affairs for energy supplier Direct Energy.
“You can’t question her stamina and her tenacity at any point,” he said. “Interestingly, she finds herself on both sides of the table depending on the issues. Sometimes, she’ll be joined at the hip with industrial customers. Sometimes, she’ll be aligned with us. … She has an interesting job where she’s advocating for things that are consistent for her constituencies, but her constituencies are often aligned with different parties.”
She came to Texas ROSE as its executive director in 1992 after working at the Public Utility Commission of Texas for most of the 1980s. She is the organization’s first, and still only, employee. “When I took the job, all I had was the [organization’s] charter,” she said. “I had no office. Even the [tax] paperwork wasn’t finished for the IRS.”
In the ensuing two-plus decades, she has built the organization up enough to take the state’s electricity industry head on and found some success. From suspicious billing charges to questionable customer service practices, she campaigns to maintain the balance for consumer interests in a system that she feels is heavily weighted toward the industry.
The Regulator Experience
“It was amazing to me the amount of hold the industry had on what happened at the agency,” Biedrzycki said of her time at the PUC.
In fact, she found herself at one point in charge of a meeting to explain rules to industry representatives who she felt were actively trying to not understand them. As the person responsible for reviewing utilities’ energy efficiency programs, she kept hearing from the industry that they didn’t understand the rules. So she called a meeting of the stakeholders to hash out the misunderstandings.
The meeting was well attended, but completely silent.
“They wouldn’t ask a question, they wouldn’t say a word,” Biedrzycki remembers. “I managed to … provide them with what I thought the rule meant, and then the meeting was over. … If they would have been cooperative, then they would have had to submit something that made sense and fulfilled what we thought the requirements of the rule were.”
Instead, she felt, they wanted to maintain their plausible ignorance. “They really didn’t want to ever admit to understanding what the rule meant because they had no intention of complying with it,” she said.
The experience was one that molded Biedrzycki’s persistence. “I just stood in front of that room, and I thought, ‘It’s a good thing I’ve got three brothers who have given me a hard time my whole life’ because I was not really intimidated by them.”
The Story of Texas ROSE
In 1987, the PUC’s energy efficiency division was moved by the state legislature to the governor’s office and renamed the Energy Management Center. Biedrzycki moved with it to continue her work on increasing energy efficiency in the state, but she eventually left and ended up doing consulting work for federal energy efficiency programs.
The legislature earmarked funds for a consumer representation program to be administered through the Office of Public Utility Counsel, but the office thought it should be handled by a nonprofit. Texas ROSE was formed by a group of Austin insiders, who hired Biedrzycki as its executive director.
“The original purpose of the organization was to be a party at cases at the PUC, and I knew a lot of about that because I had direct involvement with it,” Biedrzycki said. “I also knew that it was a worthwhile endeavor because my experience is if you participate as a formal party at the commission … you always got something as a result of it.”
When ROSE’s state funding was eliminated, Biedrzycki scrambled to keep it afloat. The organization is now funded completely by grants, some of which come through Biedrzycki’s collaboration with the Texas Legal Services Center.
“The industry came after me,” she said. “I knew exactly what was going on, and I think they were kind of surprised when I showed up after” the funding was cut.
Staying the course is the first rule of winning regulatory battles, she said. “It’s a game of attrition. They just wait for people to become sick of it and get tired of it and drop off,” she said. “I always tell people: don’t start a utility issue unless you are prepared to carry it all the way through, because it’s the only way that you will see benefit and succeed. … As soon as you don’t show up, they think that you don’t care anymore and that you’re done with it.”
For all of her commitment, Biedrzycki appreciates that it’s mirrored by her organizations’ dedication in her.
“It’s just kinda nice to have people on your side,” she explains about why she took the position at Texas ROSE. “It was a wonderful thing to have people speak to you, ‘We think that what you’re doing is really important.’ How great is that? It doesn’t get much better than that.”
Bringing Back the Regulation
Biedrzycki’s biggest complaint about the industry is what she sees as the failure of power deregulation. Even before it arrived in Texas in 2002, she had been fighting for years to derail the deregulation movement and has spent the subsequent 14 years trying to get the price of power generation regulated again. She points out that several other states have done so and others, including Ohio, are considering it as well.
She believes deregulation was a mistake that hasn’t gotten better, Biedrzycki said. She regularly hears stories of consumers with bills that are hundreds of dollars a month. “I don’t have a background in economics,” she said, “but they took a business that had no middleman and inserted multiple middlemen. Just from a practical standpoint, that never made any sense to me.”
The Power to Choose
In the meantime, she’s remained focused on what she can do for consumers by recommending improvements to the PUC’s retail choice website, on which electric providers list their offers. While the site has received many improvements over the years, it can get better, she said. More than anything, she feels it needs to be simplified. There are too many plans, too much fine print and too much research required by consumers who were fine with just paying the bill when it arrived every month, she said.
“My own personal opinion is [companies] should not be permitted to charge fees for anything that they are required to do under the PUC’s rules because then that way everybody just has to include that cost in their rates and it makes it better for the consumer from a cost comparison perspective,” Biedrzycki said. “I’m really tired of everybody blaming everything on the consumer. You should be able to pay your bill and be left alone, and you should be able to be happy.”
Her opinions are backed up by nearly 100 comments from consumers on the issue filed with the PUC in May. Short and to the point, nearly each comment riffs on the same theme: buying electricity is too complicated. Biedrzycki would like to see the site have a way to calculate estimated monthly bills, along with requiring each retail electric provider to offer a plan that fits a standardized, PUC-approved model so consumers can make easy comparisons.
A recent workshop on the issue with PUC Chairman Donna Nelson produced another of Texas ROSE’s sometimes strange alliances.
“We found ourselves aligning on the vast majority of issues,” Direct Energy’s Ross said, “because we both were trying to find ways to reduce consumer confusion and make shopping easier.”
Respecting the Process
Despite her contentious positions, Biedrzycki’s years of dedication have afforded her respect. It was more than 10 years ago when she was working for the governor’s office that Nelson met Biedrzycki.
“She’s always struck me as someone who wanted to make a change. She wasn’t there for a paycheck,” Nelson said. “Carol does a really good job of representing her client base, which is low-income customers, but she really represents all residential customers — people who often don’t have a voice.”
Nelson also acknowledges that some companies have been “shysters” and “in many cases,” Texas ROSE has provided the information needed to heavily fine them or revoke their certifications. Biedrzycki has also engaged the PUC on several other projects, including revamping rules for company disclosures and ensuring the commercial viability of natural gas retailers.
“I don’t always agree with her, but I usually come to modify the position I went in with originally,” Nelson said. “You always want that counterbalance to what the utility or what the competitors in the competitive market want. … I’ve found that when I get everybody in a room, sometimes the [retail electric providers] will learn something from Carol.”
Building on her past success, Biedrzycki envisions a way for customers to import their actual usage data from the Smart Meter Texas website so they can quickly see how their monthly bills under each plan are likely to look. (See PUCT to Look at Smart Meter Web Portal.)
Aside from those future goals, Biedrzycki continues to advocate for billing assistance, weatherization programs and rate discounts for low-income consumers.
Nelson said it’s hard to have personal relationships while trying to be unbiased, but it’s also impossible not to become familiar because the same people present before the PUC so often that it’s “a small family.” She and Biedrzycki have shared similar medical experiences, and Nelson has noticed some of Biedrzycki’s quirks.
“Sometimes when she testifies, she puts her comments on pink paper so they stand out,” Nelson said. “She’s reasonable, but she’s passionate. Here you lose your credibility if you’re difficult.”
Richard Sedano, a principle at the Regulatory Assistance Project, met Biedrzycki when his organization convened meetings to bring consumer and environmental advocates together. He found out exactly what folks in Austin already knew.
“She is certainly not a shy person. She stepped up and said things she felt needed to be said,” he remembered. “Carol is her own person. … I thought she was really terrific.”
Outside the Office
Expecting to retire in perhaps a year and a half, Biedrzycki is already planning her next moves. Never married and an avid patron of the theater, she plans to spend her summers with family in Pittsburgh, Pa., and return to Austin when the theater season starts up in the fall. She volunteers at several theaters in town.
She is also planning to find a successor to groom. “That’s one thing that I have on the back burner,” she said.
While Biedrzycki has so many changes she’d like to see, she knows to take the long view. Just keep asking the questions, and eventually someone will answer.
“I think her presence [at meetings] — although maybe it’s uncomfortable at times for those who are on the other side — I think people take comfort that she’s there so that [her] interests are represented,” Ross said.
FERC is giving respondents until Sept. 2 to provide comments on recommended changes to Order 1000 following a June technical conference at which some participants suggested complete overhauls of the landmark rule and others said it’s too early to tell if changes are necessary (AD16-18). (See Five Years Later, FERC Takes Another Look at Order 1000.)
The order, which sought to increase transmission development by eliminating incumbent utilities’ right of first refusal and creating incentives for more innovative, cost-effective and efficient projects, has been slow to produce results.
FERC asked for comments on “the use of cost containment provisions, the relationship of competitive transmission development to transmission incentives, and other ratemaking and transmission planning and development issues.”
