Page 1411 – RTO Insider

August 15, 2016

CAISO Plans to Protect Small Utilities from High Network Upgrade Costs

By Robert Mullin

A new CAISO proposal seeks to shield smaller participating transmission owners from outsized network upgrade costs for interconnecting generation built to serve load outside that TO’s service area.

“The issue is — to what extent should a local area incur costs for resources that are clearly not serving that area?” Neil Millar, CAISO executive director of infrastructure development, said during an August 8 call to discuss the proposal.

“Network upgrades on low-voltage facilities for [TOs] with a relatively low rate base can significantly increase costs [for those PTOs],” said Steve Rutty, the ISO’s director of grid assets. “Similar upgrades would not have much of an impact” on larger TOs.

The proposal stems from the situation confronting Valley Electric Association, which serves 45,000 customers located in a 6,800-square-mile region straddling the California-Nevada border. The utility — CAISO’s only out-of-state member — has about 100 MW of load. Two projects awaiting interconnection will bring 100 MW of new generation into Valley’s territory, with more entering the queue, according to Rutty.

Valley Electric Association Territory (CAISO) - utilities high network upgrade costs — Valley Electric Association, which joined the ISO in 2013, serves about 45,000 customers in its 6,800 square mile territory.

“So we’re looking at hundreds of megawatts for an area with just 100 MW of load,” Rutty said.

CAISO’s Tariff requires a TO to reimburse its generator interconnection customers for the costs of local reliability and deliverability network upgrades necessary to connect to the transmission network. With regulators’ approval, the TO can then include those reimbursement costs in its rate base and pass them on to ratepayers through either a high- or low-voltage transmission access charge (TAC). The ISO considers any line under 200 kV to fall into the latter category.

Postage Stamp Rate

Unlike CAISO’s high-voltage TAC, which is allocated to all ISO ratepayers at a “postage stamp” rate based on the aggregated revenue requirements of all TOs owning high-voltage lines, the low-voltage TAC is charged only to customers within the service area of the TO owning the facilities.

That arrangement could impose an unfair financial burden on ratepayers served by small TOs such as Valley.

“[I]f a large generator or a large number of generators with significant low-voltage network upgrade costs interconnect to a [TO] with a relatively small rate base, that [TO’s] rate base may increase significantly and can result in rate shock to its ratepayers,” the ISO said in its straw proposal.

The ISO estimates that $25 million in network upgrade costs would boost Valley’s low-voltage TAC from $6.26/MWh to $12.13/MWh — a 94% increase.

“There’s a considerable amount of interest in Valley for renewables,” said ISO attorney Bill Weaver. “If all the projects come online, $25 million is not unreasonable to expect.”

But those projects will not provide a “commensurate benefit” for the utility’s ratepayers, CAISO said.

The ISO has proposed two options to address the issue, which it expects to occur again if the ISO expands into other areas of the West and takes on additional small TOs.

The first option would allow a TO to roll “generator-triggered” low-voltage network upgrade costs into its high-voltage revenue requirement for recovery through its high-voltage TAC. The rationale: Any new generation will provide energy for the entire ISO market or support policy goals such as resource adequacy, reliability and increased renewables.

Under this scenario, $25 million in upgrades in the Valley area would translate into a 1.5-cent/MWh — 0.14% — increase in high-voltage TAC rates shared by all ISO ratepayers.

“This option would apply to all PTOs, is straightforward and would be fairly simple to implement,” the ISO said.

“This raised the question of whether local upgrades are helping the local area — which brought up the issue of some kind of cost sharing,” Millar said. “Which brought us to option two.”

The second, more complicated, option would split cost recovery for low-voltage upgrades between a TO’s low-voltage and high-voltage TACs. The split would be assessed in such a way as to cap increases to a TO’s low-voltage revenue requirement and TAC. Any amount above the cap would be applied to the TO’s high-voltage revenue requirement and thereby rolled into the ISO’s TAC.

Three Options

The ISO is considering three methods for calculating the split:

Place a cap on the cost share of interconnection-driven upgrades assigned to a TO based on a percentage — possibly 5% — of the TO’s low-voltage base rate. TO’s with smaller base rates would be capped at significantly lower amounts than the larger investor-owned utilities.
Limit incremental increases to a TO’s low-voltage revenue requirement based on a percentage of the TO’s annual low-voltage revenue requirement.
Limit incremental increases in the revenue requirement to a percentage of the high-voltage TAC revenue recovered from the TO’s ratepayer base.

“This last method would make sense because it limits exposure of a local area group of customers to a percentage of their high-voltage TAC payments,” the ISO said. “As such, a utility twice the size of another could reasonably absorb twice the local impact of interconnection-related low-voltage network upgrades compared to a utility with a much smaller customer base.”

“We want to know the justification for the proposal,” said Lanette Kozlowski, director of regulatory relations at Pacific Gas and Electric. “Is it just the rate impact for the customers of [Valley Electric]?”

“That’s overly simplistic,” said Millar. “The cost issue certainly puts a spotlight on it, but it’s more about resources being developed in an area that won’t be serving that area.”

“How is this going to align with the other utilities where you’re connecting to the network and it’s being fully paid for by the project?” asked Don Davie, vice president with Wellhead Electric. “What are you thinking about for cost-causation for the actual project?”

“We’re not really going to propose shifting the costs to interconnection customers,” Millar said.

ISO staff plans to submit a final plan to the Board of Governors in December. Stakeholders must submit comments about the straw proposal by Aug. 19.

August 12, 2016

UPDATED: PJM, NYISO Seek Input on Replacing Con Ed-PSEG ‘Wheel’

By Peter Key and Rory D. Sweeney

VALLEY FORGE, Pa. — PJM and NYISO held a joint meeting on Monday to get stakeholder feedback on their effort to replace a decades-old power-flow protocol.

The RTOs must have a new protocol in place next May when Consolidated Edison terminates a “wheel” arrangement that allows it to move 1,000 MW from generators in upstate New York through Public Service Electric and Gas facilities in northern New Jersey to serve its load in New York City.

The main question is how to handle eight phase angle regulators (PARs) that currently govern the direction of flows on lines connecting the PJM and NYISO grids. There are one each on the A, B and C lines that flow the 1,000 MW from PSE&G into New York; three south of Waldwick on the J and K lines that flow the energy into PSE&G from upstate New York; and two on the Branchburg-Ramapo 5018 line.

At PJM, the situation is being overseen through the Planning, Market Implementation and Operating committees. During last week’s Planning Committee meeting, PJM’s Mark Sims explained that the PARs have more physical limitations than HVDC ties, which can be more specific in regulating flow. The PARs can be set to certain “tap positions” to “bias” the flow, but each of them has a limit of 20 adjustments per day and 400 per month.

At Monday’s meeting, PJM and NYISO staffers gave presentations on the operational aspects and market impacts of the wheel replacement.

Phil D’Antonio, PJM’s manager for reliability engineering, said the new protocol must protect reliability, manage congestion, preserve competitive market behavior and minimize the impacts to PJM and NYISO loads. It also must be able to be facilitated with the existing PAR technology and implemented in both grid operators’ market models.

On the markets side, PJM and NYISO are proposing adding the J, K, A, B and C lines into the single PJM-NY AC Interface and implementing market-to-market coordination using the PARs on the lines’ interfaces. The RTOs said the proposal uses existing market constructs in both their markets, increasing the likelihood it can be implemented by next May.

The review of the new protocol will include an N-1-1 analysis.

PJM and NYISO have agreed not to change their treatment of Rockland Electric Co.’s load, 80% of which is supplied by the 5018 line, with the remainder flowing over several western ties across the New York-Pennsylvania border.

One of the proposals being evaluated — the “natural flow” — would send about 500 MW from NYISO into PJM via the J and K lines and then into New York City via the A, B and C lines, Sims said. Stakeholders have questioned allowing this because it appears to provide similar service to the “wheel” without the same transmission payments. Completely curtailing that natural flow, or modeling 0 MW, threatens to “max out” the PARs’ thermal and voltage limits, Sims said.

Among the “high-level” considerations that the grid operators are discussing are biasing the flows applied to the J, K, A, B and C lines by accounting for the natural flow, and then applying agreed-upon interchange percentages to each interface (5018 and ABC) to reduce congestion.

NYISO published a white paper on the process and will partner with PJM to publish another one that includes PJM’s perspective, which will be released in conjunction with a meeting of NYISO stakeholders.

Stakeholders have asked PJM to create a contingency plan for extended outages of the PARs.

August 12, 2016

NRG Continues to Pare Down Businesses, Affirms Guidance

By Tom Kleckner

NRG Energy continues to retrench after a dismal 2015, announcing last week it will sell its stake in the California Valley Solar Ranch and restructure its GenOn unit, whose acquisition in 2012 nearly doubled NRG’s generation portfolio.

New Jersey-based NRG also said it had sold two Illinois gas plants for $425 million, helping the corporation deliver $779 million in adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) for the quarter. NRG has generated almost $1.6 billion in adjusted EBITDA — or cash flow — this year, putting it in the upper range as it reaffirmed its guidance for 2016 ($3 billion to $3.2 billion).

“We have a lot of the summer ahead of us. I think it’s just prudent to keep our guidance the way we had it,” interim CEO Mauricio Gutierrez said during a conference call with analysts. “We’re very comfortable with the positon we have. We still have August and September, which can be really hot in Texas.”

nrg energy — NRG Energy’s El Segundo Plant *Source: NRG*

NRG said it has reached agreement to sell its 51% stake in the 250-MW California Valley solar project for $78.5 million in cash plus assumed debt to NRG Yield. NRG Yield is a separate, publicly traded company that has 4,438 MW of renewable and conventional generation under contract; NRG Energy owns 55.1% of the yieldco’s outstanding common stock.

The company also said GenOn has appointed two independent directors and retained restructuring advisors “to help navigate the [restructuring] process efficiently and judiciously” in a bid to reduce its “excessive” leverage ratio.

GenOn, which has $2.6 billion in debt, is expected to generate only $335 million in EBITDA in 2016 — a leverage ratio of 7.7, far above the 4.2 ratio for the company as a whole and the 4.0 ratio the company is seeking to reach by the end of the year.

NRG’s $1.7 billion acquisition of GenOn boosted the company to 47 GW of generating capacity, making it the largest competitive generator in the U.S. But the 22.7 GW acquired from GenOn — coal, natural gas and oil — have not fared well due to the entry of increasingly competitive renewables and more efficient plants burning cheap shale gas.

NRG said its second quarter net loss of $276 million ($0.61/share) — worse than its $9 million loss a year ago — resulted from $198 million in impairments and losses on asset sales and an $80 million loss related to extinguishing debt.

Excluding one-time charges, the company’s loss was $0.04/share, below Zacks Investment Research’s consensus expectations of a $0.03/share profit. NRG reported $2.64 billion in quarterly revenues, well below Zacks’ consensus projection of $3.45 billion.

The company had a net loss of $229 million ($0.37/share) for the first six months of this year, after recording a $6.44 billion loss in the fourth quarter of 2015, which ended with the resignation of CEO David Crane.

NRG shares were down 5.6% in the two days following the Aug. 9 earnings announcement, closing off 75 cents at $12.76 Wednesday.

NRG serves more than 3 million residential customers throughout the country, primarily in Texas and the Northeast.

August 10, 2016

ISO-NE Ordered to Justify Cost of Winter Reliability Program

By William Opalka

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.

August 10, 2016

MISO Will Use ATC Plan to End Upper Peninsula SSR

By Amanda Durish Cook

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.

ATC submitted the proposal to MISO in late July. (See ATC Plan Could Eliminate White Pine SSR; Refunds Coming on Presque Isle?)

“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.

August 9, 2016

UPDATE: ERCOT Surpasses 70,000 MW, Sets Six Hourly Peak Demand Records

By Tom Kleckner

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.

August 9, 2016

PJM OKs $636M in Tx Projects, Including its Largest Market Efficiency Proposal

By Suzanne Herel

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.

At the same meeting at which it approved AP South, the board halted another Order 1000 project, the stability fix for New Jersey’s Artificial Island. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)

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.

August 9, 2016January 23, 2024

Governor Delays CAISO Regionalization Effort

By Robert Mullin

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.)

Still, some critics were concerned about the rush to complete the proposal in time to seek approval from lawmakers before the current legislative session concludes later this summer. (See Governance Plan Critics Urge Slowdown of Western RTO Development.)

“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.”

August 8, 2016

MISO Delays Forward Auction Filing; Issues Draft Tariff and Business Rules

By Amanda Durish Cook

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.’”

Demand Curve Shape not Decided

Bladen © RTO Insider — Bladen © *RTO Insider*

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.

Michael Chiasson, of the Independent Market Monitor, stressed “the importance of having adequate time to review the Brattle analysis.” (See MISO Backs Forward Auction Plan, Rejects Prompt Proposal.)

PJM Influence

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.

“To us, they’re complicating things,” Dauphinais said.

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.

August 8, 2016

NY Attempts to Thread Legal Needle with Clean Energy Standard, Nuke Incentives

By William Opalka

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.)

Nine Mile Point (Constellation-Energy-Nuclear-Group) new york clean energy standard — *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.