Page 1371 – RTO Insider

December 12, 2016

MISO Board Approves MTEP 16’s $2.7B in Tx Projects

By Amanda Durish Cook

CARMEL, Ind. — MISO’s 2016 Transmission Expansion Plan, with 383 projects totaling $2.7 billion, won the Board of Directors’ unanimous approval Dec. 7.

The 13th annual transmission package shed 11 projects and $100 million in investment from the preliminary plan that was unveiled in September. (See MTEP 16 Proposes 394 Projects at $2.8 Billion.)

The approved plan calls for less spending on fewer projects than MTEP 15’s $2.75 billion on 345 projects. It brings transmission investment in the footprint to 1,246 projects totaling about $15.6 billion since 2003.

miso board mtep — Curran | © *RTO Insider*

MISO Vice President of System Planning and Seams Coordination Jennifer Curran said some stakeholders wrote a letter encouraging the RTO to open the plan’s lone market efficiency project — the $80.9 million Huntley-Wilmarth 345-kV line in Minnesota — to competitive bidding.

The project, however, is covered by the state’s right-of-first-refusal statute. Curran said MISO counsel conducted another legal review of the Huntley-Wilmarth project and concluded that the RTO must respect state and local laws. “It would be inconsistent with our Tariff, and our Tariff respects that right-of-first-refusal law,” she said.

MISO Director Michael Evans asked if there was anything else the RTO could research about the legality of opening Huntley-Wilmarth to competitive bidding, but Vice President of Transmission and Technology Clair Moeller said, “Based on our Tariff and state law, we’re right where we need to be.”

“MTEP is a remarkable document. Planning from the Gulf of Mexico to the Hudson Bay is a dream … and it’s being done very well,” Evans concluded. “The direction of change remains the same, but the pace of change is up in the air.”

Evolving Fleet Influencing MTEP Futures Regardless of Presidency

Curran said MTEP 17’s futures, which on average predict a one-third coal, one-third gas and one-third renewables mix by 2030, are still relevant, despite the election of Donald Trump, who has vowed to “save” the coal industry. (See related story, Trump Transition Bodes Ill for Clean Power Plan.)

During the Dec. 6 System Planning Committee of the Board of Directors meeting, Curran said she expects three unchanged futures to be finalized in 2017. (See “MTEP 17 Futures Finalized,” MISO Planning Advisory Committee Briefs.)

“This is a more interesting topic since the election,” Curran said. “We’ve gotten a lot of calls since the election asking what has changed. In our view, we see our generation fleet continuing to evolve.”

Curran said the real uncertainty facing MISO is how fast those changes will take place, but she said regardless of federal energy policy and the presidency, fleet evolution will continue.

“We see and hear our members and state’s intentions to move forward with a lower-carbon fleet,” Curran said, citing carbon reduction measures in states’ fixed resource adequacy plans, continued low gas prices and the number of renewables in MISO’s interconnection queue, where wind comprised 69% of total megawatts reaching the queue’s definitive planning phase in 2016.

Curran said in the next 15 years, 8 GW of coal could retire based on the average 65-year coal unit lifespan and 16 GW of natural gas and oil generators could retire assuming their average 55-year lifespan. She said MISO plans to initiate a study in 2017 to examine the reliability impacts of aged-based generation retirements.

Moeller said MISO’s aim is simple: political-free planning.

“The most important criteria is that we’re working on the right thing. I think we’re pointed towards that,” Evans said.

December 12, 2016

IMM Report Highlights Outages, Wind Over-Forecasting

By Amanda Durish Cook

CARMEL, Ind. — High generation outage rates in MISO South and suspicions of deliberate over-forecasting by wind operators highlighted the concerns of MISO’s Independent Market Monitor in the fall.

Monitor David Patton presented the draft of his fall report at the Dec. 6 meeting of the Markets Committee of the Board of Directors, saying that MISO’s markets performed “competitively and reliably” with “infrequent” market mitigation.

miso imm outage rates — MISO’s Markets Committee of the Board of Directors listens to IMM David Patton’s conference report. | © *RTO Insider*

MISO’s fall load peaked at 115 GW on Sept. 6. Patton said a 15% increase in real-time energy prices from last fall could be traced to a 13% increase in natural gas prices over the same period last year. He said a 4% year-over-year increase in wind output — which set a new record at 13.3 GW of production on Nov. 28 — led to higher congestion and price volatility. Combined with high levels of generator outages, there was higher congestion in the day-ahead and real-time markets relative to last year, Patton said.

Day-ahead congestion increased by 18% over 2015 to $202.7 million and real-time congestion increased by 9% to $345.1 million. “Prices, particularly in the three southern hubs in October jumped up … due to some pretty significant congestion,” Patton said.

Outages Approach 40%

Patton said generation outages in MISO South were of particular concern, increasing from an average of 18.2% in fall 2015 to 31.6% in fall 2016. As October approached, Patton said, MISO South outage rates almost reached 40%. “This is an unusually large quantity to have out,” he said.

Unseasonably warm weather produced unusually high loads and led to a maximum generation alert Oct. 4-5. Patton said the tight conditions were due in part to the high outage rates in MISO South.

“It appears that if we could do anything better as a market, it’s managing the scheduling of the outages in MISO South,” Vice President of System Planning and Seams Coordination Jennifer Curran said.

“That’s fair,” Patton responded, adding that MISO should have more authority over generation outages.

Vice President of System Operations Todd Ramey said high temperatures and the high number of scheduled outages, combined with forced outages and derates, contributed to the reliability concerns.

“As an industry we tend to focus on the winter, but it’s true that the most challenging situations are the shoulder periods where outages are high,” Ramey said. He also said MISO is taking “a hard look” at adjusting outage coordination in MISO South. Jeff Bladen, executive director of market services, said the season proved the value of the North-South transfer path, as the outages were offset by MISO North power.

Curran said the Tariff might need to be “opened up” to give MISO the authority to coordinate planned outages in advance “so you aren’t just responding to the conditions as they’re dealt, but you can influence them.”

Wind Operators’ ‘Bias’

Patton repeated concerns that wind operators were deliberately over-forecasting their supply to earn more from MISO’s day-ahead margin assurance payment. (See MISO IMM Sees Deliberate Over-Forecasting by Wind Operators.)

Board member Baljit Dail asked if Patton had a sense of the size of the overpayments.

Patton said that while he didn’t find gaming had occurred “in an obvious fashion,” he estimated MISO has paid $6 million in unjustified payments over the past year to year and a half. “The [wind operators] are not forecasting badly because they don’t have the technology; they’re forecasting badly because they have a bias,” Patton said.

Richard Doying, MISO’s executive vice president of operations and corporate services, said the RTO continues to evaluate instances of wind over-forecasting and would approach the board with findings and possible solutions later.

Director Phyllis Currie defended the RTO, saying it is looking to put people and resources in place to conduct their own wind forecasts. “Load forecasting is not an exact science,” she pointed out.

Patton agreed that MISO should not rush a solution.

On average in fall 2016, wind units predicted an average day-ahead wind supply of 4,324 MW and produced 5,141 MW in real time.

Patton also told the board that he continues to work with MISO on expanding a pilot program to create temperature-adjusted transmission ratings. “When temperatures are cooler, you can transfer a lot more power,” Patton said.

December 12, 2016

Increased Transfer Capacity Reducing EIM Congestion

By Robert Mullin

Increased transfer capacity is keeping a lid on congestion in the Western Energy Imbalance Market (EIM) and limiting participants’ ability to wield market power within their balancing authority areas, according to CAISO’s internal Market Monitor.

Gabe Murtaugh, a senior economist with the ISO’s Department of Market Monitoring, told a Dec. 7 Market Performance and Planning Forum that the increased capacity could help Arizona Public Service, NV Energy and PacifiCorp in reapplying to FERC for market-based rate authority. Citing market power concerns, FERC has limited the three companies to cost-based offers. (See CAISO Monitor Proposes Fixes for EIM Market Power Concerns.)

Puget Sound Energy — the only EIM member currently permitted to make market-based offers — has committed to the market 300 MW of bidirectional transfer capacity with the PacifiCorp-West balancing area. Those transmission links were congested during just 1% of intervals in the May-October period, Murtaugh said.

APS’ average outbound/inbound EIM transfer capability of 1,874 MW/924 MW with CAISO saw almost no congestion during the period, while the utility’s 321-MW/216-MW link with PacifiCorp-East showed congestion during 1% and 7% of intervals, respectively. Despite the proximity of their balancing areas, there is no EIM transfer capability between APS and NV Energy because of the limited availability of capacity to commit to the market.

Average transfer capacity among CAISO, NV Energy and PacifiCorp-East remained steady from May to October, and links between the areas were subject to relatively light congestion over the period. PacifiCorp-East’s outbound link into NV Energy was most congested during spring, when inland power prices are cheap.

The one exception to low congestion: transfers from PacifiCorp-West into CAISO via limited capacity available on the California-Oregon Intertie. The intertie is congested 20% of the time, in part because of the variability of transfer capacity made available to the EIM during given intervals.

Graphic illustrates the percentage of intervals for which each EIM intertie was constrained during May-October and the average volume of transfers during each congest interval. Figures for Arizona Public Service and Puget Sound Energy are for October only. | *CAISO*

“Generation in PacifiCorp-West is generally cheaper than generation that we see in the ISO and the rest of the EIM,” Murtaugh said. “And when prices are high in the ISO, [PacifiCorp-West] generation increases its output until it reaches its limit for export.”

That constraint has historically led to price separation between PacifiCorp-West and the rest of the EIM.

PacifiCorp’s new EIM link with Puget Sound Energy is alleviating that isolation in most hours. Now, when there is congestion between PacifiCorp and CAISO, the ample transfer capability between PacifiCorp-West and Puget Sound means that PacifiCorp prices are set by the marginal generation in both areas, rather than just PacifiCorp-West, Murtaugh said.

But Pacific Northwest prices will still tend to diverge from the rest of the market.

“When prices are higher in the rest of the system, we see generation about as high as it can get in PacifiCorp-West,” Murtaugh said.

That pushes on the constraint out of PacifiCorp-West, causing price discrepancies between that area — and, now, Puget Sound as well — and the remainder of the EIM.

While price divergences stemming from congestion drive concerns about market power in the EIM, the Monitor finds that congestion is occurring in “a very low percentage of intervals” — even in the five-minute market, when congestion tends to be most elevated.

“The underlying message here is there isn’t a whole lot of opportunity to exercise market power during [most] intervals,” Murtaugh said.

December 9, 2016

Entergy, Consumers Announce Closure of Palisades Nuke

By Tom Kleckner

Citing market conditions that have changed “substantially” and the availability of “more economic alternatives,” Entergy announced Thursday it intends to shut down its Palisades nuclear plant on Oct. 1, 2018.

Entergy said a power purchase agreement between the plant, located in Covert Township, Mich., and Consumers Energy would be terminated four years early in 2018. Consumers will pay Entergy $172 million for terminating the PPA. According to Entergy, the termination will also save Consumers customers $172 million in costs over four years.

The companies entered the 15-year PPA in 2007, when Entergy bought the plant from Consumers parent CMS Energy for $380 million. However, the agreement’s prices exceed market prices and escalate each year, reaching $61.50/MWh in 2022.

“We determined that a shutdown in 2018 is prudent when comparing the transaction to the business risks of continued operation,” Entergy CEO Leo Denault said in a press release.

In its most recent 10Q, Entergy said the “fair value of the Palisades plant would have been, and currently would be, significantly lower in the absence of the power purchase agreement that is scheduled to expire in 2022.” It also pointed to the drop in energy prices in MISO, in which Palisades operates.

Palisades Nuclear Power Plant | *Palisades Power*

The early termination payment “will help assure the plant’s transition from operations to decommissioning,” Entergy said. The plant will be refueled as scheduled next spring and then operate through the end of its fuel cycle.

With Palisades’ closure, Entergy will have only one nuclear generating facility in its Wholesale Commodities business, the 40- and 42-year-old Indian Point units near Manhattan. Like other plants in the portfolio, Palisades is older (1971) and smaller (811 MW) than later-generation nuclear units.

In February, Entergy estimated the plant’s fair value and related long-lived assets at $463 million, compared to a carrying value of $859 million. It said last month the wholesale business lost $13 million in the third quarter as compared to the previous year because of lower-realized wholesale prices.

In recent years, the company has shut down or announced the closure of its Vermont Yankee and Pilgrim plants in New England. And on Wednesday, FERC approved the sale of its James A. FitzPatrick plant in New York to Exelon. (See related story, FERC Approves FitzPatrick Sale to Exelon.)

“Entergy’s strategy is to manage risks by reducing our merchant power market portfolio and invest in the growth of our regulated utility business,” Entergy spokesperson Val Gent said. Entergy still owns five nuclear reactors in the South as part of its utility generating business.

Reaction

The agreement between Entergy and Consumers is subject to regulatory approvals, including the Michigan Public Service Commission, but the announcement quickly drew pushback from elected officials in the state.

State Rep. Aric Nesbitt (R), who chairs the House Committee on Energy Policy and whose southwestern Michigan district is home to Palisades, called Entergy’s announcement a “punch in the stomach” and said it “puts Michigan’s energy future at greater risk.”

“I call on Entergy to reconsider its decision to prematurely close Palisades and work with the state to find a solution to keep Palisades open and producing reliable, emission-free energy,” he said in a press release. “This announcement further threatens Michigan electric reliability after 2018. This is not just a bad decision for our local families, but it is also the wrong decision for Michigan’s energy future. I demand that Entergy reconsider this poorly made decision.”

Gov. Rick Snyder was more subdued. In a statement issued by his office, Snyder said, “I’m certain the Michigan Public Service Commission will look at this very closely and examine the implications for the reliability and affordability of electricity in Michigan, as well as protection of the environment.

“No matter what the eventual decision is, it is important that we do everything to help the region adapt to a potential future without Palisades,” he said.

For its part, MISO will follow its normal confidential process for generator retirements to determine whether Palisades’ absence will jeopardize reliability. The RTO’s Tariff requires companies to notify it at least 26 weeks before the proposed retirement, which then sets the clock on a study evaluating any reliability issues.

Entergy said it expects to recognize an approximately $390 million non-cash impairment charge ($252 million after taxes) in the fourth quarter and another $55 million in relevant charges through the end of 2018.

The corporation’s stock price, which closed Wednesday at $70.44/share, opened the day at $69.88/share before erasing the early drop. Entergy’s share price climbed to $70.55/share by early afternoon.

December 8, 2016

FERC Approves FitzPatrick Sale to Exelon

By William Opalka

FERC on Wednesday approved Exelon’s acquisition of the troubled James A. FitzPatrick nuclear plant in New York, rejecting a protest that its review should have included the impact of a state-mandated ratepayer subsidy (EC16-169).

Plant owner Entergy told New York officials that without the $110 million sale, the 882-MW plant would close at the end of January. New York regulators approved the transaction last month. (See NY Regulators Approve FitzPatrick Sale.)

But consumer advocate Public Citizen, in a protest filed with FERC in October, complained that the companies omitted information on the zero-emission credit program New York had passed to prop up upstate nuclear plants, which the group argued made the application incomplete. It also said the subsidy itself distorts the New York market and violates the NYISO Tariff. (See Public Citizen Challenges NY Nuclear Subsidy, FitzPatrick Sale.)

entergy, fitzpatrick, exelon, public citizen, nuclear power — FitzPatrick Nuclear Plant | *Entergy*

Entergy and Exelon said such a review was beyond the scope of FERC evaluation of the sale, which should be limited to whether it gave the buyer excess market power and if the sale was in the public interest.

The commission agreed.

“We will dismiss Public Citizen’s protest of the proposed transaction because the issues Public Citizen raises concern the ZEC program rather than the effects of the proposed transaction on competition, rates, regulation or cross-subsidization,” the commission wrote. “Public Citizen … focuses on the potential effects of the ZEC program on the NYISO market rather than the effects of the proposed transaction.”

FERC said such questions could be addressed in another proceeding, which Public Citizen appears prepared to do.

Tyson Slocum, director of Public Citizen’s energy program, on Thursday said the groups would first ask for a rehearing of this week’s order and later challenge the ZECs under a Section 206 proceeding.

Slocum said he found FERC’s rationale “very strange” for limiting the scope of order.

“It’s very clear that the transaction would not have occurred without the ZEC program,” he said. “But there was no review of how [ZECs] will affect market power, pricing and how it gives [the plants] a competitive advantage.

“FERC is acting as if these changes to the market don’t exist,” Slocum added.

Critics of the ZEC program say it will cost ratepayers $7.6 billion over its 12-year life. New York says the program helps combat climate change and its costs are more accurately measured by the federal “social cost of carbon” calculation.

After the Nuclear Regulatory Commission gives its approval and the deal closes, Exelon will be the sole owner of the upstate nuclear fleet, which consists of three plants that make up 5.9% of the state’s generation.

December 8, 2016

FERC OKs W.Va. Tx Rate over Staff, Honorable Objections

By Rory D. Sweeney

FERC delivered a split decision in approving a rate settlement on a West Virginia transmission project that was opposed by both FERC staff and Commissioner Colette Honorable.

ferc transmission rate uncontested settlements — | © *RTO Insider*

Chairman Norman Bay and Commissioner Cheryl LaFleur said the settlement between Transource West Virginia, Old Dominion Electric Cooperative and Midcontinent MCN was more favorable to the public interest than the uncertainty of litigation (ER15-2114). Honorable opposed the Dec. 5 order, however, saying the only party to the docket truly representing the public interest was FERC staff, which opposed the settlement.

At question was Transource’s rate of return on equity for its Thorofare Creek–Goff Run–Powell Mountain 138-kV project awarded through PJM’s Regional Transmission Expansion Plan. Transource had initially proposed a 10.5% base ROE, which was reduced to 10% in the settlement. FERC staff argued a discounted cash flow analysis indicated an 8.89% rate was appropriate.

The settlement also negotiated a moratorium on changes to the base rate until Sept. 5, 2018, along with finalizing depreciation rates and clarifying the formula-rate template. Incentive rates had already received FERC approval and weren’t part of the settlement.

Noting support for the settlement from ODEC and Midcontinent, Bay and LaFleur said the commission “favors settlements, as they provide parties with certainty, reduce litigation cost, and permit parties to reach reasonable compromise in resolving difficult issues.” The 10% rate is consistent with rates approved in other recent uncontested settlements, they said, and denying it might upset the settlement’s other agreements. Staff’s DCF analysis would certainly be challenged in litigation, which might produce a rate well above the settled one, they said.

Honorable noted language in FERC’s approval of one of the recent uncontested settlements that describes “a case where the commission staff is the only participant to represent the interests of the ultimate consumer.”

“This settlement is the situation envisioned by the commission,” she wrote in her dissent. “Based on the record in this proceeding, I am unable to conclude that the settling parties represent all aspects of the public interest.”

While ODEC had intervened in the case, Honorable said she couldn’t determine whether the cooperative would be allocated any costs for the project, thereby giving it little stake in the case’s result and reducing the significance of its acceptance of the settlement. Staff’s determination, she said, should have received more consideration and ultimately informed the commission’s decision.

December 8, 2016

FERC Backs MISO on Transfer Limit, Seeks Details

By Amanda Durish Cook

FERC dismissed a complaint seeking to overturn the results of MISO’s 2016/17 Planning Resource Auction but ordered the RTO to specify how it calculates the sub-regional transfer constraint in its Tariff.

The commission found the RTO didn’t violate its Tariff when it calculated its sub-regional export constraint for the 2016/17 auction by subtracting firm transmission reservations from the initial 2,500-MW South-to-North transfer limit (EL16-112).

A coalition of MISO transmission customers made the complaint in September, arguing that the RTO’s PRA limits are too strict and drove up clearing prices by trapping capacity in MISO South. MISO defended its method and said it plans to reuse it in future capacity auctions. (See MISO Recommends No Change to Transfer Limits.)

The commission said the RTO acted correctly and that no refunds were warranted. “MISO’s approach considered the [SPP] settlement agreement and the transmission service reservations in the prevailing direction found therein. Despite claims that other approaches could, or even should, have been used, there is no evidence to suggest that MISO’s calculation of the sub-regional export constraint was inconsistent with its Tariff provisions,” the Dec. 6 order said.

However, FERC ordered MISO to specify in its Tariff the methodology used in sub-regional export and import constraint calculations. The commission said the RTO must provide the methodology by the end of January “in order to accommodate the ongoing stakeholder process and allow MISO’s filing to be informed by it.”

Tariff revisions are also to include a formula for going-forward costs. In its complaint, the MISO transmission customers asked FERC to audit offers into the 2016/17 auction, claiming some facility-specific reference levels — which are based on going-forward costs — were too high. FERC declined, saying costs to operate and maintain MISO’s aging generation fleet would naturally rise, but it told the RTO to describe how going-forward costs are established.

December 8, 2016

CAISO Refines Small TO Generator Interconnection Plan

By Robert Mullin

CAISO has narrowed a proposal to protect smaller transmission owners from high costs for network upgrades to interconnect generation serving load outside the TOs’ service territories.

The revised proposal seeks to more specifically target the situation confronted by Valley Electric Association. Any policy changes would likely also apply to other small TOs added by the ISO through regional expansion. (See CAISO Plans to Protect Small Utilities from High Network Upgrade Costs.)

CAISO generator interconnection plan — CAISO is seeking to create a plan to shield small transmission-owning members like Valley Electric Association from costly transmission upgrades associated with generators not serving the utility’s customers. | *Valley Electric Association*

Valley Electric — CAISO’s only out-of-state member — serves 45,000 customers and about 100 MW of load in a 6,800-square-mile region straddling the California-Nevada border.

The utility’s service area sits within an area considered promising for new renewable development that would serve other parts of the ISO. Two projects with a total capacity of 100 MW await interconnection with the Valley system, with more expected to enter the queue, according to the ISO.

Under CAISO’s Tariff, a TO must reimburse generator interconnection customers for the costs of local reliability and deliverability network upgrades necessary to connect a generating unit to the transmission network.

Upon regulatory approval, the TO can include those reimbursement costs in its rate base — passing them on to ratepayers through either a high-voltage or local low-voltage transmission access charge (TAC). The ISO considers any line under 200 kV to fall into the latter category.

Postage Stamp

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

That arrangement can burden ratepayers in low-population service areas who are forced to bear the low-voltage network upgrade costs for generation intended to serve other, more populous locations attempting to meet renewable mandates.

“So the question — through this initiative — that we ask is, ‘Does this current mechanism for network upgrade cost recovery appropriately allocate costs in accordance with FERC’s allocation principles?’” Bob Emmert, CAISO manager of interconnection resources, said during a Dec. 5 call to discuss the latest version of the proposal.

The revision scales back what the original proposal offered for stakeholder consideration, including eliminating a proposed cost recovery provision that would have enabled all TOs regardless of size to roll “generator-triggered” low-voltage upgrade costs into its high-voltage revenue requirement to be recovered through the high-voltage TAC.

Under the revised proposal, only small TOs would be allowed to fold generator-driven low-voltage costs into their high-voltage revenue requirements.

The exception: when a generator is being built to serve the TO in some manner. Associated costs would then be put into the TO’s low-voltage TAC rates.

“After reading [stakeholder] comments, the ISO came to agree that the current cost allocation rules have resulted in appropriate cost allocation overall — and they continue to work for generator interconnections for the large load-serving entities,” Emmert said.

Based on input from most stakeholders, the updated proposal narrows its focus, only addressing the specific circumstances of utilities such as Valley Electric.

Options

The revised proposal sets out an “Option A” that would require the ISO to determine on a case-by-case basis whether a candidate TO should be allowed to fold low-voltage generator interconnection costs into high-voltage transmission revenue requirements, thereby diffusing the costs among the ISO’s rate base. The ISO would make its determination based on whether the TO is:

Very small relative to other TOs;
Located in a renewable resource-rich area gaining “elevated” interest for generator procurements; or
Not subject to a renewable portfolio standard or has already met its requirements.

Each TO entering the ISO under that option would have to be approved by both the Board of Governors and FERC.

A more “formulaic” Tariff-based “Option B” would retain the second two points from Option A but specify that a TO’s annual gross load be no larger than 5% of the gross load for the ISO’s largest TO. Valley Electric’s load represents 0.6% of the largest TO.

“This is the criteria that was going to be the most consistent,” Emmert said. “We’d considered using a comparison against the ISO’s annual gross load, but the ISO could grow and that might change. We felt that the largest [TO] is going to remain the largest [TO] and that would remain pretty consistent over time.”

Lee Terry of California’s State Water Project expressed concern that some generation interconnected with Valley Electric’s low-voltage system could be built to serve nearby Las Vegas, rather than ISO load.

“My knee-jerk reaction would be that we would consider that to be the same as if it were serving the [participating transmission owner] in some manner,” said Bill Weaver, an ISO attorney. “Maybe we should consider broadening that [provision] to non-CAISO [TOs] rather than the [TO] itself.”

‘Strong Support’

Southern California Edison’s Fernando Cornejo expressed his company’s “strong support” for the latest draft of the proposal.

“SCE commends the CAISO for taking a more surgical approach to a cost allocation issue that we do believe is very exceptional and unique to a Valley Electric Association type of situation,” Cornejo said. “We believe that the existing cost allocation and the bifurcation between high-voltage and low-voltage upgrades has been long-established through the cost structure and pricing paradigm that’s been in place for several decades.”

Not all utilities were as satisfied.

John Newton, a regulatory analyst with Pacific Gas and Electric, said his company opposed the ISO’s decision to scrap the cost-allocation option that would have allowed all utilities to roll low-voltage generator interconnection costs into the high-voltage TAC.

While PG&E was “sympathetic” to Valley Electric’s concerns, the allocation methodologies had been in place since the Nevada utility had joined the ISO, Newton said.

For that reason, PG&E supported the scrapped option, which he called a “non-discriminatory policy change which would fairly treat interconnection costs the same for all transmission owners” participating in the ISO.

“We’re disappointed with these Options A and B and it’s unacceptable to PG&E,” Newton said.

December 7, 2016

ERCOT Addresses Transmission Planning Challenges with New Rule

By Tom Kleckner

AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week approved a revision to the ISO’s planning guide that some stakeholders called the most important policy change this year.

The planning guide revision request (PGRR042) changes the criteria used to determine the need for new transmission projects. It defines considerations for selecting the most appropriate demand forecast in planning studies and how to address certain generation resources, such as switchable and mothballed units, in planning cases.

The change also describes how to incorporate new generation units in sensitivity analyses when they have interconnection agreements, but have not met all the requirements to be included in transmission-planning studies.

[Editor’s Note: An earlier version of this story incorrectly stated that the rule change would require a 2,800-MW reserve and spell out maximum dispatch levels for wind and solar generation. Those provisions were deleted from the revision that was approved by the TAC.]

‘Critically Important’

ercot transmission planning challenges — Barnes | © *RTO Insider*

“It’s critically important to have balance in our planning process, because we’ve observed transmission costs and the transmission projects this planning criteria applies to are some of the most expensive items this stakeholder body reviews and approves,” said Reliant Energy’s Bill Barnes. “It has an impact on the cost to consumers, it has an impact on the market … there has to be some balance in the planning process. [The change] makes a lot of sense and is a huge step forward in how we think about planning the transmission system, and being responsive to the needs of the competitive market.”

“This is perhaps the most meaningful transmission reform since I’ve been involved with ERCOT,” said Shell Energy’s Greg Thurnher. “I don’t know that ERCOT has had discretion in the past to push back on some of the inputs to the planning process.”

The TAC approved the PGGR, which has been two years in the making, by a 24-4 vote with one abstention. ERCOT’s board of directors will take up the measure during its Dec. 13 meeting.

Cost Concern

The revision drew some pushback from stakeholders concerned about a revised impact analysis filed in October that indicated the need for two additional full-time positions at an estimated cost of $260,000-280,000. Committee members asked ERCOT staff to “beef up” its business case for the two positions before the board meeting.

Jeff Billo, the ISO’s senior manager for transmission planning, said the new staff is necessary to address increased responsibilities and workload being placed on his department and ERCOT’s forecasting unit, each of which would receive one new employee. The latter group’s work task is complicated by creating forecasts for ERCOT’s non-opt-in entities (Austin Energy, San Antonio’s CPS Energy and the Lower Colorado River Authority) and differences between the ISO’s use of coincident forecasts and transmission providers’ reliance on adding up individual substation forecasts.

“Part of the work in my group is not only [performing additional sensitivity] studies, but working with the load forecasting group to ensure we’re providing the proper load forecast,” Billo said. “The additional FTE is making sure we get the numbers right with our load forecasts.”

“The bottom line is this will affect the [administrative] fee,” the LCRA’s John Dumas said.

Barnes said he was sensitive to Dumas’ concerns, but said the cost “pales in comparison to the benefits this rule change will give us.”

‘Pretty Compelling’

Noting ERCOT’s Tier 2 transmission projects cost at least $50 million, Barnes said, “If we find through this rule change that this saves one unnecessary Tier 2 project of $50 million anytime in the next 100 years, it will have met the criteria for the cost-benefit case, and that’s pretty compelling.”

Responding to a comment that recalled ERCOT saying it wouldn’t raise its admin fee for the next several years, ERCOT COO Cheryl Mele said, “Hopefully, two FTEs is not enough to damage that expectation going forward.”

Some TAC members also raised questions about the proposed use of the “bounded higher of” load forecast methodology—in which ERCOT will compare its load forecast with the summed bus-level forecast for each weather zone. A motion to table PGRR042 for a month was easily defeated by a 21-7 margin, with one abstention.

“We’re interested in working through and talking about whether the higher-up bounding methodology makes sense,” said Luminant Generation’s Amanda Frazier. “There are a lot of open questions around … whether there should be different values between weather zones … we are concerned about codifying the process before that discussion happens.”

The TAC’s endorsement will allow staff to use the new planning methodology as it begins developing the 2017 Regional Transmission Plan in January. Following next year’s “test drive,” the methodology will become effective in 2018.

“Going to board now allow us to get started with 2017 planning under the new assumptions and studies,” Billo said.

December 7, 2016

Pipeline Sues to Force NY to Issue Permit for CPV Plant

By William Opalka

Millennium Pipeline has taken New York to federal court to force action on a gas line needed for an under-construction power plant entangled in a corruption scandal (16-1415).

In a 32-page brief filed Monday with the D.C. Circuit Court of Appeals, the company says the state Department of Environmental Conservation is sitting on a water quality permit for a 7.8-mile lateral needed to supply the Valley Energy Center plant being built by Competitive Power Ventures in Orange County.

The department must issue a Section 401 Clean Water Act permit for the project to proceed. Millennium says the department has ignored deadlines under the CWA, Natural Gas Act and a FERC order.

“By failing to act within a year of receiving Millennium’s permit request, the department thus has waived its authority to deny that request,” the suit says. “FERC set an Aug. 7, 2016, deadline for all decisions on federal authorizations relating to the Valley Lateral Project. The department missed that generous deadline by more than three-and-a-half months (and counting).”

FERC issued a certificate of convenience and public necessity for the line Nov. 9 (CP16-17).

cpv millenium pipeline — Artist rendition of CPV Valley Energy project | *CPV*

The $39 million Valley Lateral project would connect the plant to Millennium’s main pipeline through the Lower Hudson Valley. State and NYISO officials say the plant is needed to relieve generation and transmission constraints to serve the capacity zone north of New York City.

Millennium applied for the water permit in November 2015. DEC issued a Notice of Incomplete Application in December 2015 and a second NOIA in June, to which Millennium responded Aug. 31.

A DEC spokesman said the department does not comment on matters under litigation.

The department told Millennium on Nov. 18 that it had received the pipeline’s response to its second NOIA and that its review of the project was ongoing. The department said it has until Aug. 30, 2017, to issue the permit, in effect arguing that the one-year deadline for action restarted when it received the response to the second NOIA in August.

The $1 billion, 650-MW generating plant, which has been opposed by environmentalists, also has a role in an ongoing political scandal that resulted in the indictment of Joseph Percoco, a former top aide to Gov. Andrew Cuomo.

Former CPV executive Peter Galbraith Kelly Jr. has also been indicted in the bribery scheme. (See Competitive Power Ventures Lobbyist, Former Cuomo Aides Named in Bribery Indictment.)

Millennium has not been implicated in the scandal.