Page 1531 – RTO Insider

April 28, 2017

DC Circuit Puts Hold on CPP, MATS Challenges

By Michael Brooks and Rich Heidorn Jr.

The D.C. Circuit Court of Appeals granted the Trump administration’s requests to hold in abeyance lawsuits challenging EPA’s Clean Power Plan and Mercury and Air Toxics Standards, small but important victories for the president — just before his 100th day in office — as he tries to reverse the Obama administration’s regulations on fossil fuel-fired power plants.

The orders also come just before a march in D.C. protesting President Trump’s policies on climate change.

The administration filed its requests on the CPP and MATS cases — along with several others regarding numerous lawsuits concerning Obama-era environmental regulations — shortly after Trump signed an executive order at EPA headquarters last month directing agencies to review all existing regulations “that potentially burden the development or use of domestically produced energy resources.” (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)

The court on Friday ordered the suit against the CPP, filed by 26 states , to be paused for 60 days, with EPA required to file a status report in 30 days.

Stay

Implementation of the CPP was stayed by the Supreme Court in February 2016, shortly after the states filed their challenge, and the D.C. Circuit heard more than seven hours of oral arguments in September. The stay was a surprise to many and came without explanation, but it’s likely the Supreme Court wanted to avoid what happened with MATS.

The court in June 2015 found that rule illegal because EPA had not considered its costs. But because the rule, first proposed in March 2011, had not been stayed during the years of litigation, companies had been making investments and closing power plants in order to comply by the April 2015 effective date.

Instead of voiding the rule, the Supreme Court remanded the case back to the D.C. Circuit, which ordered EPA to rewrite the rule with a proper cost-benefit analysis. The court’s Thursday order suspended the case until further notice. EPA is required to file a status report in 90 days.

The holds give the administration more time to figure out how to revise — or potentially rescind — the rules. It is unclear how it intends to do this. But in the case of the CPP, the order does stave off the court from potentially upholding the rule.

Chief Judge Merrick Garland did not participate in the order, as he had recused himself from cases while his nomination to the Supreme Court by President Obama was pending before the Senate.

EPA Request

EPA asked the court to delay action on the CPP challenge on March 28, the day Trump signed an executive order directing EPA Administrator Scott Pruitt to begin the lengthy process of undoing the rule.

“The Clean Power Plan is under close scrutiny by the EPA, and the prior positions taken by the agency with respect to the rule do not necessarily reflect its ultimate conclusions,” EPA said in its motion. “EPA should be afforded the opportunity to fully review the Clean Power Plan and respond to the president’s direction in a manner that is consistent with the terms of the executive order, the Clean Air Act and the agency’s inherent authority to reconsider past decisions. Deferral of further judicial proceedings is thus warranted.”

Environmental groups — including the Sierra Club, Environmental Defense Fund and Natural Resources Defense Council — filed a response April 5 contending that EPA’s request “would have the effect of improperly suspending the rule without review by any court, without any explanation and without mandatory administrative process.”

“The relief EPA seeks flouts the terms of the order by which the Supreme Court temporarily stayed enforcement of the rule. The Supreme Court did not invalidate the rule; consistent with the authority granted courts by the Administrative Procedure Act, it issued a stay pending a decision by this court and an opportunity for Supreme Court review. Now EPA wants the stay, but not the judicial review that formed the basis for it,” they wrote. “Granting EPA’s motion would effectively convert that temporary enforcement relief pending judicial review into a long-term suspension of the rule likely continuing for years, without any court having issued any decision on the rule’s merits.”

CPP’s Vulnerabilities

Based on the judges’ questions and comments during oral arguments in September, it appeared four of the five challenges — a Constitutional issue; a bill drafting error; EPA’s alleged failure to provide sufficient notice of changes between the original and final plan; and a claim that it relied on dubious assumptions on the growth of renewables — had little chance of prevailing. But the judges seemed to be seriously considering the argument that EPA overreached its authority by creating CO₂ emission limits that coal-fired generators can’t meet, forcing a “generation switch” to natural gas and renewables. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

Some observers say the administration may not succeed in killing the CPP, and that if it does, it will have little impact because the power industry’s decarbonization will continue without the rule.

At a panel discussion at the Energy Bar Association annual conference in April, David Doniger, director of the NRDC’s Climate and Clean Air program, said that most of the players in the electric industry have adjusted to the CPP’s goals and are unlikely to reduce decarbonization efforts because of Trump’s action.

“Whatever its noble objectives, it’s relatively irrelevant whether or not [the CPP is] enforced,” added panelist Ian C. Connor, global co-head of J.P. Morgan’s Power & Utility Group. “I have little doubt … that the industry will materially decarbonize and outstrip what the CPP is trying to do.” (See EBA Panel: CPP’s Demise not Certain — and it Doesn’t Matter.)

CPP Supporters: EPA Must Act on Carbon

New York Attorney General Eric T. Schneiderman tweeted in response to the court’s action Friday: “Despite today’s temporary pause in litigation, the facts remain the same: @EPA is still legally obligated to limit carbon pollution.”

“We are in a race against time to address the climate crisis,” EDF General Counsel Vickie Patton said. “The Supreme Court is clear that EPA has a duty to protect Americans from dangerous climate pollution under our nation’s clean air laws, and Environmental Defense Fund will take swift action to ensure that EPA carries out its responsibilities under the law. Climate progress and clean energy cannot be stopped by the litigation tactics of polluters.”

CPP Opponents: Good Riddance

William Yeatman, senior fellow at the Competitive Enterprise Institute, which opposes the CPP, said the action means one of two potential outcomes: “1) Either the rule is nixed because the EPA determines that it is precluded from issuing a climate rule for existing power plants because they are already regulated under the Clean Air Act’s hazardous air pollution program, or 2) the EPA significantly revises the rule to bring it ‘inside the fence line’ of electricity generating units, such that the agency no longer claims the authority to dictate to the states what their energy choices must be.

“Either way, the outcome will pardon the American economy from the ill-effects of the Clean Power Plan, which would have empowered the EPA to remake the electric industry,” Yeatman said.

Jeff Holmstead, a partner with the Bracewell law firm who headed the EPA’s Office of Air and Radiation from 2001 to 2005, called the news “important but not terribly surprising.”

“I don’t think the D.C. Circuit has ever gone ahead and decided on the legality of a rule when a new administration says it plans to rescind or revise it. The only question now is whether the case will be held in abeyance or remanded back to EPA. If the court had upheld the rule, it wouldn’t have prevented the new administration from revoking it, but it might have made this effort harder. At the very least, today’s ruling means that it will not take as long for the administration to undo the Clean Power Plan.”

April 27, 2017

PJM Asked to Explain Day-Ahead Commitment Assumptions

By Rory D. Sweeney

VALLEY FORGE, Pa. — Is PJM’s day-ahead auction more art or science?

That question was raised by several stakeholders at Tuesday’s special session of the Market Implementation Committee on price transparency, after the disclosure that PJM operators — rather than algorithms — make the final decision on which units clear the day-ahead auction.

PJM day-ahead auction — Scarpignato (right) and Adam Keech, PJM | © *RTO Insider*

PJM’s Mike Ward, who manages the day-ahead market operations, downplayed human involvement in the process, saying “most of the tweaking is on the edges.” But that didn’t satisfy Calpine’s David “Scarp” Scarpignato or Public Service Enterprise Group’s Gary Greiner, who questioned the subjectivity of the operators.

“I’m sure you’re doing things that ‘make sense,’ but when you get people making the decisions, I could adjust things differently around the edges than what you might,” Scarp said.

“We’ll run two, three, four more cases to keep adjusting it. We don’t just take it [once], that’s it and we approve it,” Ward said. “It’s hard to describe how we do it. … I judge [the benefit or harm] by the number of people calling and complaining.”

To avoid cutting into units’ profit, the operators compare LMPs to costs, Ward said, and consider many other factors, such as minimum or maximum runtimes.

“Are there rules for that or is it more art than science?” Greiner asked.

“We don’t want people to lose money,” Ward responded. He noted that the percentage of load bidding into the day-ahead auction has risen from 75% when he started to “close to 100%” today.

PJM’s Chris Callaghan explained the RTO’s commitment review process, which ensures system reliability by allowing reliability engineers to provide input for commitment decisions and review the final plan. Any additional units identified as necessary from that final reliability check are committed in the Reliability Assessment and Commitment run. Engineers look first at non-cost options, followed by gas-fired combustion turbines, then by steam-generation units to satisfy reliability at the least cost, he said.

Continuing the discussion on price formation, PJM’s Scott Benner explained the RTO’s current thinking on complying with FERC Order 831, issued in November. The order caps at $2,000/MWh all incremental offers allowed to set LMPs and requires validation of offers exceeding $1,000/MWh to “ensure that a resource’s cost-based incremental energy offer reasonably reflects that resource’s actual or expected costs.”

PJM plans to implement a process to address those requirements in November but must submit its compliance filing by May 8, Benner said. A third-party vendor will provide “near real-time” commodity prices to enable PJM to calculate theoretical cost-based offers and compare them with actual offers received.

“We should be able to understand their costs or at least their general spot market activity,” Benner said.

“We’d be checking to make sure if your offer was in accordance with your fuel-cost policy,” PJM’s Jeff Schmitt said.

Throughout the presentations, stakeholders and PJM staff recommended objectives for the group’s final product, many of which focused on providing deeper insight into how the RTO makes price-formation decisions.

April 26, 2017

DC Circuit Upholds FERC Ruling in PURPA Dispute

By Wayne Barber

The D.C. Circuit Court of Appeals on Tuesday declined to overturn a FERC decision requiring Portland General Electric to purchase the full output of an Oregon wind power project under the Public Utilities Regulatory Policies Act.

The three-judge panel also rejected a claim by PáTu Wind Farm that PGE was required to accept the wind producer’s power through dynamic scheduling.

The court dismissed the utility’s petition for lack of jurisdiction and denied PáTu’s argument on its merits.

PURPA ferc power purchase agreement — Pa’Tu Wind Farm Construction | *PaTu / White Construction Company*

The case centered on a 2015 FERC ruling in which the commission determined that PGE must purchase all of the six-turbine, 9-MW wind farm’s power under a power purchase agreement between the two parties set out under PURPA.

Because PáTu, located in rural Oregon, is not directly linked to PGE’s grid, it sells power to the utility under the state Public Utility Commission’s approved PPA for “off-system” generators.

In order to transmit power to PGE’s grid, PáTu obtains transmission services from the Wasco Electric Cooperative and the Bonneville Power Administration. Wasco wheels PáTu’s power to BPA, which in turn transmits the energy to PGE’s Troutdale substation, the PPA’s designated point of delivery.

“Before the ink had dried on the power purchase agreement, the parties locked in a dispute over the nature of Portland’s purchase obligation,” the court said.

Believing it had purchased a firm product, PGE required PáTu to set day-ahead schedules under which the wind farm committed to delivering whole blocks of energy for each hour of the day. If PáTu overscheduled its deliveries, PGE paid the favorable avoided cost rates for the power delivered and required the wind farm to make up the difference by buying firm power from BPA, which was compensated at the lower market rate because it was not generated by PáTu.

On the other hand, if PáTu underscheduled, PGE only accepted and paid for only scheduled deliveries, forcing the wind farm to dispose of the excess at less-favorable rates, the D.C. Circuit noted.

PáTu contended that PGE could only buy all of its variable output through “dynamic transfer” — or scheduling in real time. PGE countered that, under its PURPA agreement, the wind farm was a customer of the utility’s merchant arm, not a transmission customer, and was therefore ineligible for dynamic scheduling.

In December 2011, PáTu filed a complaint with the PUC. The regulator saw nothing in the PPA requiring PGE to utilize dynamic scheduling, concluding that the utility must purchase all power PáTu generates and delivers.

But drawing a distinction between power “produced” and power “delivered,” the PUC appeared to leave PGE free to refuse to purchase any power produced in excess of what PáTu scheduled.

PáTu appealed to the Oregon Court of Appeals, which affirmed the PUC’s decision without opinion. The wind farm owner then filed a complaint with FERC, arguing that PGE must buy all of its output, scheduled or not, and that dynamic scheduling was the only way to accomplish that result.

FERC concluded that the PPA and PURPA regulations required PGE “to accept PáTu’s entire net output … delivered to Portland,” the D.C. Circuit noted.

FERC rejected PáTu’s specific request for dynamic scheduling, explaining that it has never required a utility to use any particular method to carry out its purchase obligation. It nonetheless clarified that, contrary to what the PUC had suggested, PGE could not escape its PURPA obligation by imposing overly rigid scheduling requirements or by refusing to purchase all power that PáTu produces.

April 26, 2017April 30, 2025

CAISO Considers Fast-Track Approval for 2 Tx Projects

By Robert Mullin

CAISO management is considering whether to approve two low-cost transmission upgrade projects using an accelerated procedure that bypasses the usual stakeholder process and the Board of Governors.

One project would entail landscaping changes needed to accommodate an uprate on the Pacific DC Intertie, Southern California’s direct link with hydroelectric generation coming out of the Pacific Northwest.

The other would employ cutting-edge technology to avert the temporary threat of summertime overloading on key transmission lines serving the San Diego area.

CAISO bylaws allow for ISO management to approve projects with capital costs less than $50 million on an expedited basis under conditions in which there is an “urgent” need for the project, coupled with a “high degree of certainty” those projects won’t conflict with other solutions being considered in the normal transmission planning process.

Another requirement is the accelerated timeline must be “driven by the ISO’s evaluation process or external circumstances,” according to CAISO. The process also comes with some obligations on the part of management, including requirements to allow stakeholders to review and comment on the project, followed by a briefing of the board.

The two projects under consideration could receive approval early next month, the ISO said.

External developments are driving the need for the proposed Pacific DC Intertie project, requested by Southern California Edison in response to upgrades performed by the Bonneville Power Administration at the line’s northern terminus at Celilo Station, near The Dalles Dam in Oregon.

Bonneville Power Administration upgrades at Celilo Station — the northern terminus of the Pacific DC Intertie — has prompted CAISO to seek expedited approval for improvements needed at the southern end of the line to allow Southern California to capture the benefits of an uprate. | © RTO Insider

BPA’s improvements have increased the line’s north-to-south transfer capability from 3,100 MW to 3,220 MW. To capture its estimated 60 MW share of the uprate, SoCalEd must pay for its portion of the costs to grade and recontour the land under the southern end of the line, which it owns jointly with the Los Angeles Department of Water and Power (LADWP).

Total costs are expected to come in at less than $1 million. CAISO considers the nudge in capacity to be “extremely cost effective” for SoCalEd — estimated at less than $10/kW.

“We do think it would be a waste not to capture the incremental benefits,” Neil Millar, the ISO’s executive director of infrastructure development, said during an April 25 call to discuss the projects.

“Barring new information to the contrary, the ISO is interested in moving forward with approval” of the intertie project, CAISO has said. SoCalEd expects LADWP to complete the grading work in October.

The proposed San Diego area project is more technologically complex.

San Diego Gas & Electric is seeking to deploy advanced power flow devices on area transmission lines in order to reduce the utility’s local capacity requirements during the summer of 2018.

The utility is concerned that completion of the Sycamore-Penasquitos 230-kV transmission project — recently pushed back from early to late June 2018 — could meet with further delays. That would increase the risk next summer of overloading the Mission-Old Town 230-kV circuit — a pair of lines serving a populous load pocket in the city — under circumstances in which peak loads shift dramatically because of variability in behind-the-meter solar output. CAISO estimates that it could be forced to shed as much as 370 MW of load within 30 minutes of a line outage.

The risk is, in part, being precipitated by the retirement of the 950-MW natural gas-fired Encina power, which could be given an extended life to help mitigate the potential overload problem until the Sycamore-Penasquitos line is energized.

John Jontry, manager of Electric Transmission Grid Planning at SDG&E, noted that keeping Encina’s capacity in reserve would be a costly solution.

“The less generation we have to procure, the less we have to pay,” Jontry said.

The utility is instead proposing using a combination of a portion of Encina generation complemented by power flow control devices installed on the Mission-Old Town line that would, in an emergency, create up to 5 ohms of impedance on the line, forcing flows into other parts of the system.

“The devices push power away from the line to which they are connected,” said Andee McCoy, an executive with Smart Wires, the company that manufactures the equipment.

McCoy added that the “breadth” of the deployment could be correlated with the amount of Encina generation expected to be online next year.

Depending on the number deployed, estimated costs run from $6 million to $12 million, compared with $8 million to $10 million for a phase-shifting transformer and $20 million to $30 million to reconducutor the lines for what is effectively a temporary issue for the utility.

Jontry also lauded the fact that a “big chunk” of the capital costs are covering devices that could be redeployed to other areas when they’re no longer needed for the Mission-Old Town line.

“We’re kind of breaking new ground here because it’s a new way of looking at utility infrastructure,” Jontry said.

CAISO will present the proposed upgrades during the board’s May 1 meeting and will take stakeholder comments until May 2.

April 25, 2017

PJM Capacity Task Force Debates the Value of Price Transparency

By Rory D. Sweeney

WILMINGTON, Del. — What’s a megawatt really worth?

That question is at the base of the current debate about PJM’s capacity market construct, which last week shifted to whether there is a willingness to consider moving away from centralized markets.

At Friday’s meeting of the Capacity Construct/Public Policy Senior Task Force, the coalition of cooperatives and municipal power authorities that initiated the task force’s creation presented an alternative perspective on the objectives of a resource adequacy construct.

The task force was approved in January after the coalition pushed for months to revisit PJM’s controversial Capacity Performance construct. It began meeting in March. (See PJM Capacity Task Force Considering 60+ ‘Design Concepts’.)

Is the Market the Problem?

Navigant economist Cliff Hamal, representing American Municipal Power, offered a critique of a presentation that PJM’s economist Hung-po Chao gave at the task force’s first meeting in March. Hamal argued that PJM’s centralized capacity market is itself the problem.

Left to right: John Farber of Delaware PSC staff, Steve Lieberman and Ed Tatum of American Municipal Power listen as Cliff Hamal (far right), an economist with Navigant, presents his analysis on the purpose of PJM’s capacity market. | © *RTO Insider*

“My goal was to try to ask the question whether the objective of this task force [should be] to maintain … what I believe to be an imperfect, problematic centralized auction and deal with state actions, or consider much broader options that have the potential to do it cleaner,” he said.

He argued that the task force’s objectives should allow consideration of market options based on long-term bilateral contracts that attract least-cost financing and have the potential to provide adequate supplies at a lower cost.

Other stakeholders questioned Hamal’s perspective, saying that eliminating the market would reduce variety and the ability to accurately price various options, potentially harming market participants.

“The buyer that enters into the long-term contract now has a liability that the rating agencies insist get shown on their books, such that by entering into this long-term contract, it increases the amount of debt that the rating agency sees and potentially results in a downgrade of the entity’s debt ratings because it’s incurring more debt,” said a representative of a generation owner that is actively building combined cycle plants. “You’re not looking at the other side of the equation for the buyer in that it increases the rate associated with all of his borrowing, and that’s a huge deterrent.”

Mike Borgatti of Gabel Associates argued the proposal limited the ability to shop for alternatives. He gave an example of buying wind production for $300/MWh when the capacity auction clearing price was $100/MWh.

“The difference there is that I know I could have bought other capacity for $100, but I liked this flavor of capacity better, so I overpaid for it,” he said. “The market has functioned correctly, and the price signal out there informed my transaction. If the price signal doesn’t exist out there, I don’t know if $300’s a good deal or a bad deal.”

Chocolate vs. Vanilla

Borgatti attempted to make the same point with a less esoteric product: ice cream.

“Look, chocolate’s over here; it’s available in the market for $3/gallon. I’m a vanilla guy, so I’m gonna go over here and I’m going to procure vanilla at a premium price because I love vanilla. That transaction is totally legitimate; I did what I wanted to … I love my vanilla. I’m sitting on my couch in my underwear having a great time,” he said. “I think it’s hard to think about a market that doesn’t have any price transparency. … It’s very difficult to know [if another construct would be better] because you got rid of the price that you would benchmark it against.”

“Your position seems to favor long-term contracts as a way to attract cheaper capital, but a potential result could be long-term contracts with cheaper capital but underlying resources that are much higher cost than other resources that would compete down the road,” Direct Energy’s Jeff Whitehead said. “If I take a 20-year position on a power plant that has a certain cost, 10 years from now, there might be another power plant technology available that’s much cheaper, so while I might get a cheaper cost of capital, I might actually get a more expensive overall solution.”

Hamal acknowledged there are tradeoffs, but he emphasized that the task force is establishing objectives at this point, not choosing among alternatives.

The remainder of the meeting attempted to distill some of the 71 objectives proposed for “a well-functioning capacity construct” into categories, but that effort fell apart as stakeholders felt the nuance of certain proposals was being lost. Dave Anders, who is facilitating the task force for PJM, decided to abandon that effort and instead include all of them into a poll to measure stakeholders’ interest in each proposed objective. PJM will be sending the poll out to all stakeholders signed up to receive notifications about the task force.

The task force also worked on developing a list of public policy initiatives states might make and plans to complete it at the next meeting, Anders said. Work will then begin on determining how to balance the state activities against PJM’s current capacity construct.

Jennifer Chen of the Natural Resources Defense Council gave a presentation on subsidies to add context to the public-policies list.

The task force has a target of the end of the year to determine if any changes to the capacity market should be made.

April 25, 2017

1 Project Recommended for MISO-SPP Coordinated Plan

By Amanda Durish Cook

Just one project from MISO and SPP’s coordinated system plan study will move forward for individual votes on regional review, officials told the Interregional Planning Stakeholder Advisory Committee meeting Monday.

The project will loop one Split Rock-Lawrence 115-kV circuit into Sioux Falls to relieve congestion on the Lawrence–Sioux Falls 115-kV line in South Dakota, on the tie line shared between the Western Area Power Administration and MISO’s Xcel territory.

Final results showed costs of $5.2 million and a 4.42 benefit-cost ratio. MISO would pay 81% of the cost and SPP the remaining 19% based on benefit estimates for the first 20 years of the congestion-relieving project.

The project faces an obstacle course of approvals before construction can begin. MISO is conducting a project vote among Planning Advisory Committee voting sectors at a special meeting on April 27 for its portion of the IPSAC vote. SPP’s IPSAC vote will occur at its Seams Steering Committee teleconference on May 3. If both RTOs approve, the project moves into a SPP-MISO Joint Planning Committee vote and then into an IPSAC review conducted via email. If the project passes all review and votes, it will face an approval process before each of the RTOs’ board of directors.

The RTOs hope the approval process concludes in October, said Adam Bell, SPP’s interregional coordinator.

MISO and SPP considered seven potential interregional projects during last year’s coordinated system plan, and in earlier estimates, the South Dakota project fell just short of the $5 million interregional project threshold in the RTOs’ joint operating agreement. Earlier estimates also showed a more even cost split between the RTOs. (See MISO-SPP Coordinated Study Yields 1 Possible Project – For Now.) Bell said recently approved generator interconnect projects in MISO’s queue shifted more of the project’s cost to MISO, as the projects will benefit from congestion relief and increased transmission ratings.

Bell said project construction is complicated by the fact that the project is a tie-line, not wholly located in either footprint, and each RTO’s portion of the construction will be handled independently. MISO staff said how the RTOs ultimately decide to split construction on the small project could be used to define an improved process for projects that cover ground in both footprints going forward.

Bell also said that some interregional projects under consideration failed because of the $5 million cost threshold, which he said the RTOs are open to changing.

Another possible interregional project was revealed on April 19, but the $153.7 million candidate — the Lacygne-Blackberry 345-kV line, 345/161-kV transformer and Blackberry-Asbury 161-kV line in Kansas — graded out with a scant 1.03 benefit-cost ratio. MISO would be allocated 5% of the cost and the remaining 95% paid by SPP.

MISO SPP coordinated system plan — Lopez | © *RTO Insider*

Davey Lopez, MISO adviser of planning coordination and strategy, said the project barely passed the required 1.0 benefit-cost ratio and the minimum 5% regional benefit thresholds in the joint operating agreement. “Any increase in cost would likely drop the benefit-cost ratio below 1, and SPP is investigating other, much cheaper solutions,” Lopez said at an April 19 MISO PAC meeting.

The project failed to win recommendation from either RTO during the interregional meeting.

April 25, 2017

ISO-NE Planning Advisory Committee Briefs

WESTBOROUGH, Mass. — Although the Marcellus Shale is currently producing about 19 Bcfd of natural gas, it remains a challenge to get that gas to New England, Tom Kiley, CEO of the Northeast Gas Association, told the ISO-NE Planning Advisory Committee on Wednesday.

“What we’re seeing now is that while projects have FERC approval, they are being denied permits by state agencies,” said Kiley, whose group represents gas distribution and transmission companies, and LNG importers.

“Projects are often being delayed one or more years — even with federal permits in hand, even with contract commitments,” Kiley said in a presentation.

Kiley cited National Fuel Gas’ response to the New York State Department of Environmental Conservation’s April 7 decision to deny water quality permits for its Northern Access pipeline. “National Fuel made a very strong statement, so we’re hoping that this pushback will lessen the resistance to new pipelines,” Kiley said. “Something has to give.”

In the statement, CEO Ronald J. Tanski said any impact of the pipeline construction on water quality would be “temporary and minor.”

“These construction activities would certainly have less effect than either exploding an entire bridge structure and dropping it into Cattaraugus Creek (Route 219) or developing and continuously operating a massive construction zone in the middle of the Hudson River (Tappan Zee Bridge) for a minimum of five years, both NYSDEC-approved projects,” Tanksi continued.

He said the state is attempting to create “a new standard that cannot possibly be met by any infrastructure project in the state that crosses streams or wetlands, whether it is a road, bridge, water or an energy infrastructure project.”

ISO-NE Embeds Behind-the-Meter PV in Load Forecasting

ISO-NE planners will capture about three-quarters of the region’s behind-the-meter solar PV in their 2017 capacity, energy, loads and transmission (CELT) load forecast, Manager of Load Forecasting Jon Black said.

The RTO began forecasting BTM PV in 2014 in response to concerns that its rapid growth would not be captured within the long-term load forecast, which relies on historical load trends. The RTO has contracted with Quantitative Business Analytics for PV production data at five-minute intervals from more than 9,000 installations in New England.

“We’re taking a lesson from Germany, where they don’t have telemetrics on every source, but a representational subset,” Black said during an update on the RTO’s efforts.

Black said that RTO staff used the last five years of data. “Before 2012, PV was insignificant, just background noise,” he explained. He used the same term — “noise” — to describe the scale of storage of PV-generated energy today and explain why the grid operator does not yet have projections for storage growth or its potential load impact.

For forecast year 2017, the CELT’s net load projections includes 479 MW of “embedded” PV, which represents 83% of the PV indicated by the forecast for the year. The RTO predicts that the embedded PV — 1.6% of load for 2017 — will rise to nearly 3% of load by 2026.

“Some people think we’re just subtracting something off the load forecast, but separate component forecasting requires reconstituting the element to have an accurate PV reading on net load data,” Black said.

He also said separately forecasting and accounting for BTM PV as the RTO is doing will provide protection against the risk of under-forecasting load if the timing of the summer peak shifts later in the day as PV output diminishes, or if growth in BTM PV slows down from its recent pace.

Eversource to Build Control House at Mount Tom

Eversource Energy and ISO-NE told the PAC they support a $7.7 million project to keep the Mount Tom switchyard and build a control house.

Eversource’s Carl Benker gave a presentation on the plan, a response to Dynegy’s announcement that it will retire its 146-MW coal-fired Mount Tom Generating Station on June 1, 2018, and demolish the facility.

Because the three 115-kV transmission lines to which the plant is connected (line 1039 to Midway, 1447 to Pineshed and 1428 to Fairmont) will remain in service, the protective relays, controls and a DC control power source located within the plant must be relocated.

A previously recommended solution that would reconfigure the three 115-kV lines would be less than half the cost at an estimated $3.7 million, but ISO-NE and Eversource no longer support it because it would expose Pineshed to an additional N-1 contingency that would result in disconnecting all of the line’s load.

ISO-NE and Eversource also considered and rejected three other options ranging from $9 million to $10.1 million.

ISO-NE Post-Winter Review: Uneventful

The RTO’s resource adequacy engineer, Mark Babula, said system operations over the winter months were “relatively uneventful,” but he advised the PAC that fuel security will be an issue in future, as will pending generation retirements.

The Winter Reliability Program was instrumental in augmenting liquid fuel security for the region.

Eighty-four generating units participated in the program to procure back-up oil supplies, burning 114,000 barrels and leaving more than 3 million barrels left in inventory eligible for compensation at a cost of $31.2 million (at $10.21/barrel).

Six assets provided 23 MW of interruption capability through the demand response program at a cost of $70,500. The RTO dispatched the assets once, between 6:39 and 8 a.m. on Jan. 10.

Two generators participated in the LNG program, which will cost $291,000 (171,000 MMBtu at $1.70/MMBtu).

Asked why LNG deliveries to New England pipelines showed such a sharp decline from last winter, especially in January, Babula had a one-word answer: economics.

“We … didn’t see gas go above eight bucks this winter,” he said. “Henry Hub has been like $3. Pipeline gas is always cheaper than LNG.”

According to FERC’s 2016 State of the Markets report, Algonquin Citygate prices averaged $3.10/MMBtu for all of 2016, a 35% reduction from 2015. Henry Hub prices averaged $2.48/MMBtu, down 5%, while Transco Zone 6-NY dropped 42% to $2.19/MMBtu. (See FERC: Gas Continued to Dominate in 2016.)

Next winter will be the last for the reliability program, which will be replaced in June 2018 with the Pay-for-Performance market design. The new design will increase penalties for generators that fall short of capacity commitments and provide bonuses for those that overperform.

Babula said that the 15 to 20 critical notices or operational flow orders issued by natural gas pipelines this winter — all related to extreme weather — were typical for winter. There also were six unplanned pipeline outages, all related to compressor station outages.

The region benefited from expanded gas capacity as Spectra Energy put the final piece of its 342,000 Dth/d Algonquin Incremental Market project into service on Jan. 7. Tennessee Gas Pipeline’s Connecticut Expansion project (72,000 Dth/d) was delayed until 2018, however.

ISO-NE Planning Advisory Committee mount tom — | *ISO-NE*

On March 27, FERC gave Algonquin Transmission permission to begin construction on the Connecticut portion of its Atlantic Bridge gas project connecting points in New Jersey and New York with New England and Canada’s Maritime provinces (CP16-9). The commission granted a certificate of public convenience and necessity for the project in January. (See Atlantic Bridge Project Approved by FERC.)

– Michael Kuser

April 25, 2017January 15, 2025

SPP Regional State Committee Briefs

SPP’s Regional State Committee last week approved doubling the timeframe for conducting regional cost allocation reviews (RCARs), leaving only approval from the Board of Directors this week before the change becomes official.

Staff had been conducting RCARs every three years. With board approval of the recommendation and accompanying revision request (TRR-223), those reviews will now be conducted every six years.

The Market and Operations Policy Committee earlier approved the same recommendation from the Regional Allocation Review Task Force, which said the change would save SPP manpower and consulting costs. (See “Cost Allocation Review Cycle Could Extend to 6 Years,” SPP Markets and Operations Policy Committee Briefs.)

The most recent review, RCAR II, showed more positive benefit-to-cost ratios and only one deficient transmission zone, which already has a project in the 2017 Integrated Transmission Planning assessment. SPP said it took about 2,100 staff hours and more than $417,000 in payments to outside consultants to complete the review. The first RCAR incurred a similar expense.

“It’s a really elegant solution, because it takes a tremendous amount of staff’s time,” said Donna Nelson, chair of the Public Utility Commission of Texas. “It’s a heavy lift. All of the commissioners here have been very respectful of each other, with respect to the cost-benefit analysis.”

South Dakota Public Utilities Commissioner Kristie Fiegen isn’t so sure. “I believe we could be locking in winners or losers for an extended period of time,” she said. “It concerns me we’re moving the cost allocation review out six years, but I certainly appreciate the group looking at the cost of the study. The cost-benefit ratio is extremely important to our stakeholders.”

Feigen | kristiefiegen.com

Patrick Lyons, chair of the New Mexico Public Regulation Commission, advocated for a four-year delay between reviews, but none of the other committee members backed his proposal.

Staff pointed out that any member that feels it has an imbalanced cost allocation can request relief through the MOPC. It also said it was trying to improve the review process through the use of more accurate information.

“One thing staff is doing now is using real market data and running the market [model] without that transmission, then going back to Day 1 of the market to find the value of the transmission,” SPP General Counsel Paul Suskie said. “We’re looking at possible different ways to do the RCAR.”

Wise: Few Solutions to Wind-Energy Glut

Golden Spread Electric Cooperative’s Mike Wise told the committee that his Export Pricing Task Force did not have a “whole lot of solutions” for shipping SPP’s ample wind resources out of the footprint.

“We’re waiting on members and staff to bring ideas,” said Wise, who chairs the group and the Strategic Planning Committee. “There’s no stomach inside the task force or the SPC, that I’ve heard, that we want to build transmission to export wind and have the consumers in the footprint pay for it. I would encourage anyone who wants to come get the wind to build the transmission.”

The group has prioritized several market changes — such as ramp products and storage resources — to accommodate wind exports as staff time and dollars are available over the next few years. Wise said the group would continue meeting over the next few months as “opportunities” are brought forward.

SPP has more than 16 GW of installed and operational wind capacity, another 8 GW with signed generation interconnection agreements and a potential 43 GW overall.

The task force has begun to explore coordinated transaction scheduling, which allows for near real-time scheduling of power across RTO interfaces, based on the price spread between RTOs. (PJM has adopted CTS with NYISO and plans to launch with MISO this fall.)

“We really have to work with the other RTOs,” Wise said. “It’s not MISO that needs the power, it’s the other RTOs east of MISO.”

Committee Approves CAWG Recommendations

The RSC also approved several motions from the Cost Allocation Working Group, which reports up to the committee. The items were also approved by the MOPC earlier this month.

A recommendation to approve the Seams Projects Policy Paper as consistent with previous RSC actions. The paper sets guidelines for SPP approval and cost allocation processes for non-FERC Order 1000 interregional transmission projects on a project-by-project basis.
Another recommendation to approve regional funding for SPP’s portion of a transformer project and line uprate at an Associated Electric Cooperative Inc. substation near Springfield, Mo.
Approval of RTWG-RR208, which implements the Transmission Planning Improvement Task Force’s white paper for new regional planning processes by replacing current planning schedules with an annual transmission expansion plan, creating a standardized scope; establishing a common planning model for use across the various planning processes; and creating a staff/stakeholder accountability program.
Finding MRR203 consistent with respect to the allocation of financial transmission rights. The revision adds a “last-chance” second set of auction revenue rights nominations in the monthly ARR process, where any source-to-sink path can be nominated.
Finding RR202 also consistent with the RSC’s past policy decisions with in allocating FTRs. The change complies with FERC guidance on SPP’s disparate treatment of point-to-point and network integration transmission service (NITS) during re-dispatch. NITS would be eligible for ARR during limited times of the year and only for the service not subject to redispatch, but not for long-term congestion rights. (See SPP Hopes Congestion Rights Rule Change Wins FERC OK.)

– Tom Kleckner

April 25, 2017

MISO Planning Subcommittee Briefs

CARMEL, Ind. — MISO last week presented a strawman proposal for non-transmission alternatives that includes redispatch, load shed, reconfiguration and remedial action schemes.

The Planning Advisory Committee is currently working on Business Practices Manual 020, which outlines the process for considering non-transmission alternatives. (See “Rules on Non-Transmission Alternatives Ready for PAC Review,” MISO Planning Subcommittee Briefs.)

At the April 18 Planning Subcommittee meeting, MISO officials provided details of the alternatives:

The generation redispatch option would require an evaluation to “demonstrate that there are sufficient generation units that are available to provide the incremental capacity necessary to maintain loadings and voltages within applicable [ratings], without reliance on any single unit,” MISO proposed. The RTO said no more than 10 individual units or 1,000 MW will be used in any redispatch plan. Candidates for redispatch include all network resources and energy resources, and participating generators must have a distribution factor of greater than 3%. Before using a redispatch plan that requires decommitting a resource, the RTO said it will evaluate reliability and voltage without the unit. MISO will also exclude non-dispatchable units and nuclear generation from possible redispatch solutions.
Load shed will be allowed when local planning criteria permits, MISO said. The RTO committed to flagging constraints that result in load shed of 1,000 MW or more for potential physical upgrades.
System reconfiguration will be allowed as a corrective plan, MISO said, unless reconfiguration places noninterruptible load on a transmission radial “such that a single contingency would interrupt service to multiple customers, the reconfiguration results in opening of more than a single transmission line or the reconfiguration results in transmission flows to be routed through sub-transmission or distribution facilities.”

“All three of these come from current, real-time operating procedure,” engineer Patrick Jehring said.

Remedial action schemes will use language pulled directly from NERC, with existing schemes allowed as acceptable corrective action plans. New schemes will be evaluated on a case-by-case basis. The evaluation will include expected frequency of need for a RAS and comparison of costs to install and maintain it compared to the cost of a transmission upgrade. “Remedial actions schemes must be far cheaper than a new line,” Jehring said.

Jehring also said most of the strawman was borrowed from existing MISO standards, but that the RTO still wants stakeholder suggestions. He asked for written feedback by May 5.

“How much risk to the load-serving capability is acceptable on the planning horizon?” Jehring asked stakeholders.

In response, they expressed concerns in particular on load shedding as a non-transmission alternative option.

Consultant Roberto Paliza of Indianapolis said MISO should be transparent when it identifies specific solutions. Paliza added that too much load shed to resolve contingencies can cause a concern and could make transmission construction more appealing. Planning Subcommittee liaison Jeff Webb agreed. “If the solution is load shed, we should be explaining why that is acceptable,” Webb said.

NRG Energy’s Tia Elliott asked if MISO could gather all transmission owners’ individual load shed criteria and consolidate it into a single document. “It varies across the footprint from transmission owner to transmission owner,” she said. “Not understanding what those variables are makes it difficult for stakeholders to make an informed decision.”

Jehring said MISO already posts such planning criteria, though not consolidated, on its website.

MISO Unveils MTEP 17 Transfer Analysis

As part of its 2017 Transmission Expansion Plan, MISO outlined a proposed analysis on a half-dozen MISO transfers.

MISO planning subcommittee load shed — | *MISO*

This year, MISO is proposing to study transfers between MISO North and SPP; two transfers from Manitoba Hydro to MISO North; wind resources in Northern Illinois to Ohio (both PJM territories) using MISO transmission in Indiana; MISO North and Central to MISO East; MISO Central to the Tennessee Valley Authority; and MISO South to SPP.

Scott Goodwin, MISO transfer analysis engineer, asked for stakeholders to review the transfer selection.

This year, MTEP studies include the usual base reliability and economic studies along with a trio of specialized studies: the multiyear regional transmission overlay study, a generation retirement study and the footprint diversity study, which could identify an alternative to using SPP transmission for transfers between MISO North and MISO South. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs; “Generators Identified in MISO Retirement Analysis,” MISO Planning Subcommittee Briefs.)

MTEP 17’s scope will be finalized in December.

— Amanda Durish Cook

April 25, 2017

ISO-NE Study Projects Impact of $64/ton Carbon Price

By Michael Kuser

WESTBOROUGH, Mass. — A new analysis by ISO-NE shows that increasing carbon allowance prices from $24/short ton to $64/short ton would boost the region’s LMPs by more than 30% under all six scenarios studied.

The RTO added the new sensitivity in response to stakeholders who said the $24/short ton (2015 $) allowance price used in an earlier version of the 2016 Economic Study was too low to drive the investments needed to meet greenhouse gas reduction goals. The $64 figure is based on the federal government’s estimated social cost of carbon.

Michael Henderson, ISO-NE director of regional planning and coordination, presented the results of the revised study to the Planning Advisory Committee on April 19.

The Regional Greenhouse Gas Initiative emissions cap — 91 million short tons in 2014 — is set to drop by 2.5% annually through 2020. Some activists have called on RGGI to double the cuts to 5% per year. Most of the six scenarios studied failed to meet those targets.

carbon allowance prices iso-ne allowance study — | *ISO-NE*

Dan Pierpont, manager of external affairs for CPV Towantic, asked about the “pricing effects of RGGI goal-busting performance,” while an unidentified woman participant on the phone said she wanted “RGGI-threatening scenarios clearly delineated in the executive summary for state policymakers.”

New Names for Numbered Scenarios

In place of the six numbered scenarios in the earlier draft study, Henderson said, “we’ve given nicknames to the scenarios so they’ll be intuitively obvious.” The new names are:

RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas (combined cycle units). It fails to meet the RGGI targets regardless of whether transmission constraints are modeled or not.
ISO Queue: Physically meet RPS and replace generator retirements with new renewable/clean energy. It meets the 5% RGGI reduction only in the transmission-unconstrained model and then only using the $64/ton carbon adder.
Renewables Plus: Physically meet RPS; add renewable/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage; and retire old generating units. It meets the RGGI targets under all sensitivities.
No Retirements (beyond Forward Capacity Auction 10): Meet RPS with resources under development and use RPS alternative compliance payments (ACPs) for shortfalls; add natural gas units. It fails to meet the RGGI targets under all sensitivities. It shows the highest LMPs assuming a $64/ton carbon price, averaging $69.70/MWh including transmission constraints.
Gas + ACPs: Meet RPS with resources under development and use ACP, and replace retirements with natural gas. It does not meet the RGGI targets under any sensitivity. It shows the highest LMPs under a $24/ton sensitivity, at $52.63 (transmission constrained).
RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV. It meets the RGGI targets under the $64/ton sensitivity but fails under the $24/ton transmission-constrained model. It had the lowest LMPs of all six scenarios under all sensitivities, averaging $34.12/MWh ($24/ton) and $44.21/MWh ($64/ton) with transmission constraints modeled.

“Clearly, scenarios with the heavier renewable elements, scenarios 3, 6 and 2, show the lowest CO₂ emissions,” Henderson said. “As far as load-serving entities go, there is no change in the scenario order: The least expensive remains least, and the most expensive remains most.”

Scenario 2 shows the biggest decrease in LMPs when transmission constraints are relieved, a difference of almost $22/MWh assuming $64/ton carbon.

LMPs for scenarios 4 and 5 show virtually no change with the transmission constraints modeled because they have little congestion, Henderson said.

25-MW Threshold

Henderson noted that the study applies carbon allowance prices to all generating units in New England — including those below the 25-MW threshold employed by RGGI.

Ignoring the carbon prices for smaller units could actually increase emissions, Henderson said, because high emitting small units, such as biomass, would be dispatched more often.

“The new methodology is important, for when you raise carbon prices — if you do nothing to affect the resource dispatch order — you have no effect on emissions,” Henderson said. “As the resource mix changes and you end up with a greater amount of zero-emission resources, overall emissions decrease.”

The completed study is “on track” for publication in the second quarter, and a natural gas analysis will be announced at the May or June PAC, he said.

Study of Other Options Requested

David Ismay, senior attorney for the Conservation Law Foundation, gave a presentation asking the RTO to develop and price at least two new scenarios for generation and transmission that could reduce emissions to or below the levels of Scenario 3 at a lower cost.

“By developing a range of least-cost options for such public policy-compliant futures, the result of a Least-Cost, Emissions-Compliant System Topologies Study could be used to test the ability of market reforms to deliver the desired results of the market-policy integration that is the goal of both the on-going [New England Power Pool] Integrating Markets and Public Policy (IMAPP) effort as well as FERC’s recently opened Docket No. AD17-11,” Ismay said in a letter to Henderson.

Henderson replied that the RTO “requires specificity in any suggested economic study and will not invent a new system.”

Doug Hurley of Synapse Energy Economics offered to help Ismay and the CLF develop the right metrics for their request. Other participants spoke up to support Ismay’s use of the PAC forum to address his and the foundation’s concerns.