PJM Planning and Tx Expansion Advisory Committees Briefs

VALLEY FORGE, Pa. — Stakeholders quickly approved administrative revisions to Manual 14B at last week’s Planning Committee meeting, but gaining endorsement for the newly developed Manual 14F is likely to be a more complex task.

The new manual will cover the competitive planning process. PJM, which has been updating the proposed language based on stakeholder feedback, asked members to submit any additional comments now so the manual will be up to date when it’s approved. The RTO called attention to its “decisional process diagram” (section 8, attachment 4). (See PJM Making Cost Consciousness a Focus for RTEP Redesign.)

“We really would like to get the comments now so we can integrate them,” said Steve Herling, vice president of planning.

Sharon Segner of LS Power questioned why provisions for cost containment aren’t thoroughly outlined and asked for a full vetting of the proposed text because there have been so many revisions.

PJM will bring the manual to the Markets and Reliability Committee on April 27 for a first read and hopes to receive endorsement in May.

Should I Stay or Should I Go? PJM Still Searching for Resolution to Interconnection Queue Issues

When PJM changed its interconnection queue processes several years ago, the purpose was to ensure everyone paid their fair share of infrastructure upgrades. Previously, whichever project triggered an upgrade would be on the hook for it, no matter how much it contributed to the problem. By having all projects wait in a six-month queue under the new rules, every request that contributed to an upgrade could contribute to paying for it.

“It seemed like a great idea that everybody would take a small piece of a $5 million impact,” said PJM’s Aaron Berner, who is leading the review of the interconnection process. “We haven’t come up with a way to fix it without switching back” to the earlier cost allocation process.

tariff and manual changes PJM — PJM’s Mark Sims (left) and Dave Egan | © *RTO Insider*

At issue is how to fairly allocate upgrade costs without unreasonably delaying project completions. Back when most projects were large-scale plants with long construction lead times, PJM instituted a rule that all projects would be held in a six-month queue to determine if any upgrades would be necessary for the requests in the queue. Upgrade costs that totaled less than $5 million were allocated to all projects upon the queue’s closure.

Because projects can be much smaller and completed much faster now, the six-month wait time can delay developers’ schedules. PJM is proposing a rule change that would allocate costs of upgrades to the first request that necessitates the spending. Any subsequent requests in the queue would contribute proportionally. (See PJM Considering Injection Rights for Demand Response.)

Returning to this “first to cause” strategy for upgrades less than $5 million has largely gone unchallenged by stakeholders in a series of discussions on the topic, which caused Carl Johnson, who represents the PJM Public Power Coalition, to question who among the stakeholders would be disadvantaged by the change back. He pointed out that there will be an unlucky project that receives the cost allocation.

“I’m curious how that will play out,” he said.

“That’s another incentive to coming in [to the request queue] early,” Berner said.

The Tariff and manual changes are on track to be implemented for the project queue that opens on Oct. 1, he said.

NYISO Changes Spur PJM Review of Emergency Import Abilities

With the termination of the decades-old wheeling service through North Jersey and the near-term retirement of the Indian Point Nuclear Station, PJM is reviewing its ability to import power during an emergency.

PJM’s Mark Sims said the study of its capacity emergency transfer objective (CETO) and capacity emergency transfer limit (CETL) tests assumes a locational deliverability area (LDA) is at a 90/10 load level and in a generation-capacity emergency — in other words when the “load is high and they’re having issues with generation,” Sims said.

To ensure the system has adequate deliverability, the CETL must be equal to or greater than the CETO. Those numbers are calculated through thermal and voltage analyses. Facilities whose outage transfer distribution factors (OTDF) are more than 5% are considered in violation, as are factors more than zero on transmission lines that are 345 kV or larger. The OTDF measures how power transfers using the infrastructure being studied impact the system during an outage.

“We need to take our objective and turn it into a simulation,” Sims said. “During [an] actual emergency, operators are going to do what they can do to keep the lights on. That’s what we’re trying to reflect.”

Solar Forecast Is Coming

PJM is developing a solar forecast and will need to make several Tariff and manual changes to accommodate it, said Joe Mulhern, senior engineer and project manager. The move — mandated by FERC Order 764 — comes as PJM has seen solar installations take off, from virtually nothing in 2007 to approximately 1,000 MW today.

“It’s really just so we’re ahead of the curve on solar installation,” Mulhern said.

The aggregate forecast data will be available to members for operational planning, transmission outage coordination and generation offering and scheduling. The project is targeting implementation by the end of the year. It would only apply to front-of-the-meter solar generators.

The rule changes would also require real and reactive power telemetry for solar generators of 3 MW or greater. At the Operating Committee earlier in the week, American Electric Power’s Brock Ondayko asked why such plants would also be required to report temperatures from the backside of solar panels.

“If you want it, we’ll give it to you,” Ondayko said. “I don’t know if the information is going to be accurate or not. … It seems to me just because things could be available, I think PJM should have to think of why it’s necessary.”

Staff: Developers Have no Right to Retain Previously Proposed Projects

Transmission developers whose proposals don’t get approved will need to continue proposing them until the constraint disappears or risk another developer landing the project if it ever is approved, PJM staff told participants at the Transmission Expansion Advisory Committee meeting.

One stakeholder, who declined to be quoted by name, asked about a “right of first refusal” policy, noting that he noticed several new proposals that had appeared to be the same as previous proposals.

“It seems kind of unfair” that a company could have proposed a project that was rejected, only to see a “copycat” receive approval for it later, he said.

PJM’s Herling said the idea was discussed at FERC when the competitive transmission rules were being developed, and the commission specifically ruled out such a provision.

“The bottom line is we start over every time,” Herling said. “You have to propose in every window if there’s congestion to be addressed.”

“Lesson learned,” the stakeholder replied.

— Rory D. Sweeney

April 18, 2017

NYISO Provides Update on Capacity Export Concerns

By Michael Kuser

RENSSELAER, N.Y. — NYISO updated stakeholders last week on its response to concerns over capacity exports, providing a status report on modeling revisions and recommending stakeholders consider broad policy changes as part of the ISO’s 2018 Project Prioritization Process.

The ISO is attempting to insulate consumers from anticipated capacity price spikes in the Lower Hudson Valley and New York City zones expected as a result of FERC’s October order allowing the 1,242-MW dual-fuel Roseton 1 generator to export some of its capacity to ISO-NE. The plant, 43 miles north of New York City, is in the import-constrained G-J locality.

In January, FERC approved NYISO’s plan to change its capacity market rules to recognize the impact of counterflows. The new rules use a “locality exchange factor” to reflect how much capacity from “rest of state” can replace capacity exported from an import-constrained locality. The prior rules assumed that 100% of a generator’s exports from an import-constrained area must be replaced with generation in that locality.

In February, the ISO submitted a compliance filing eliminating a one-year transition rejected by FERC (ER17-446). (See FERC OKs NYISO Capacity Revision; Rejects Transition Plan.)

ISO officials now are working with General Electric to develop a probabilistic approach to determining the locality exchange factor. The new methodology could replace the deterministic method designed last year and approved by FERC.

Emilie Nelson, vice president of market operations, told the April 12 Business Issues Committee meeting that “the subject is proving more complicated than expected.”

GE presented its proposed methodology and export topologies at the March 22 meeting of the Installed Capacity Working Group. It is expected to present preliminary results of its analysis at the working group’s April 19 meeting.

NYISO Zones F&G to ISO-NE | *General Electric presentation to NYISO Installed Capacity Working Group, March 22, 2017*

By June 1, the ISO plans to file an informational report with FERC outlining work that will remain to be done after that date.

NYISO recommended stakeholders consider the topics of capacity imports, payments to capacity-exporting generators and capacity resource interconnection service in the 2018 Project Prioritization Process, which allows stakeholders and the ISO to rank proposed initiatives against one another based on expected benefits and costs. The initial list of project candidates and descriptions will be on the agenda at the Budget & Priorities Working Group meeting April 26.

April 18, 2017

Electric Infrastructure: Sky Keeps not Falling

By Steve Huntoon

Every four years, the American Society of Civil [not Electrical] Engineers releases its Chicken Little report on American infrastructure.[1] The report says our energy infrastructure — the second largest category after roads and bridges — should get a D+.

I don’t know if the rest of the infrastructure sky is falling,[2] but when it comes to electric infrastructure, most everything in the report is wrong.[3] [To see ASCE’s response, click here.]

For starters, there is this claim: “With more than 640,000 miles of high-voltage transmission lines across the three interconnected electric transmission grids … the lower 48 states’ power grid is at full capacity, with many lines operating well beyond their design.”

The fact is that 0 (zero) transmission lines are being operated beyond their design capacity. The grid has been and continues to be designed and constructed to cover projected peak demand years in advance. And every line is operated within its design limits. The ASCE claim is alarmist and wrong.

Then there is this: “Often a single line cannot be taken out of service to perform maintenance as it will overload other interconnected lines in operation.”

Hello, this is why most maintenance is performed in off-peak months — as has been done for decades.

And this: “As a result of aging infrastructure, severe weather events, and attacks and vandalism, in 2015 Americans experienced a reported 3,571 total outages, with an average duration of 49 minutes.”

Whoa! “Total outages” is outages, large and small, across the entire country. The total number of people claimed to be affected? 13.2 million out of America’s 325 million population.[4] The average number of people affected per outage? 3,714. Yes, less than 4,000 people per outage. For an average duration of 49 minutes.

And what portion of these 3,571 outages is even attributable to allegedly overloaded infrastructure, the gravamen of the ASCE report? According to ASCE’s own data, a mere nine (yes, nine) outages are attributed to “overdemand.”[5] Major outage causes are weather and trees at 1,069, faulty equipment and human error at 942, vehicle accidents at 419, squirrels at 89, etc.

So much for the present.

As for the future, the report relies on an obsolete projection of future electric demand. Increased efficiency and distributed energy resources, among other factors, have caused the U.S. Energy Information Administration to halve projected growth between 2016 to 2025, from ASCE’s assumed 8% to the current 4%.[6] Using ASCE’s methodology, it means “needing” $467 billion instead of $934 billion over the next 10 years.

ASCE projects spending of $757 billion, so under ASCE’s own methodology, using the current EIA growth projection, we will be spending hundreds of billions more than we need to.

There’s more. Buried in the study is an implicit assumption that the efficiency of electric generation is static; in other words, the capital cost of generating electricity remains constant, so we have to keep deploying the same dollars of investment per unit of increased electric demand.

The fact is that competitive market forces inexorably force down costs and thereby prices. Recent years have seen significant increases in the efficiency of natural gas generation and reductions in the cost of new electric generation capacity.[7] In other words, we are generating more electricity per dollar of capital investment.

Finally, the report doesn’t recognize differences in how infrastructure decisions are made in this county. Other infrastructure, such as roads and bridges, do compete with other governmental spending priorities in political decisions by federal, state and local elected officials.

Electric infrastructure investment is not a political decision. It is determined by long-term planning criteria overseen in large part by independent regional (RTOs) and national (NERC) organizations, that in turn are overseen by an independent, highly regarded federal agency (FERC).[8]

Our electric infrastructure deserves an A.

Let’s save the D+ for the ASCE report.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel.

[1]http://www.infrastructurereportcard.org/wp-content/uploads/2016/10/2017-Infrastructure-Report-Card.pdf.

[2]For critiques of the “roads and bridges are crumbling” theme, see http://www.npr.org/sections/itsallpolitics/2015/07/23/425292193/surprise-americas-roads-are-improving and http://www.economicpolicyjournal.com/2016/08/donald-trump-and-perennial-myth-of.html?m=1.

[3]This column reprises an article I coauthored 15 years ago, “The Myth of the Transmission Deficit,” https://www.fortnightly.com/fortnightly/2003/11/myth-transmission-deficit. Fifteen years later the sky keeps not falling. More recently I’ve explained why big transmission is a big mistake. http://www.energy-counsel.com/docs/The-Rise-and-Fallof-BigTransmission-Fortnightly-September2015.pdf.

[4]https://powerquality.eaton.com/About-Us/News-Events/2016/PR100316.asp. Eaton, an electric equipment maker, is the source of the ASCE outage information.

[5]https://www.switchon.eaton.com/pdf/journey/business-continuity/cost-and-causes-of-downtime-infographic.pdf.

[6]EIA’s 2017 Annual Energy Outlook projects electricity sales in 2025 of 3,892 billion kWh, which is about a 4% increase over 2016 sales of 3,727 billion kWh.

[7]“Heat rate” (Btu per kWh) declines for natural gas units are shown here: https://www.eia.gov/electricity/annual/html/epa_08_01.html.

[8]There are some states where reliability is more state-overseen than federal. Yes, state commissions face some political pressure to keep rates down … but even more to not have outages.

America’s Energy Infrastructure: Room for Improvement

By Chuck Hookham, Otto J. Lynch and Adrienne Nikolic

The American Society of Civil Engineers’ 150,000 members design, build, operate and maintain infrastructure in the U.S. and globally. While roads and bridges are often the first thing to come to mind when hearing the word “infrastructure,” civil engineers also ensure Americans have access to reliable, low-cost energy from its roots (oil/gas wells, electric generation, etc.) to its delivery at the pump or outlet. As an example, each transmission line is essentially a suspension bridge of steel, concrete, wood, cable and other materials, requiring surveying, site work, foundations, structures and construction — all areas of expertise for civil engineers, working in conjunction with other engineering disciplines.

Who better to assess the health of the nation’s energy infrastructure than civil engineers?

That’s why, since 2001, ASCE’s Infrastructure Report Card has included energy infrastructure, with particular emphasis on electricity transmission and distribution infrastructure. Released every four years, the Report Card follows the familiar A-to-F format of a school report card, grading 16 categories of infrastructure. Prepared by a team of civil engineers with expertise across all categories, the Report Card serves as an unbiased, go-to source for information on the state of the nation’s infrastructure, and has been cited by U.S. presidents, countless elected officials at all levels of government, academics and media outlets.

Unfortunately, much like the overall grade across all 16 categories, the energy grade has been stalled in the D’s. In the 2017 Report Card, ASCE graded the nation’s infrastructure a D+ and energy also received a D+ — both the same as in 2013.

To determine the grades, we assess relevant data and reports, consult with technical and industry experts, and assign grades using the following key criteria: capacity, condition, funding, future need, operation and maintenance, public safety, resilience and innovation.

While U.S. energy systems are sufficient to meet the country’s projected energy needs, the 2017 Report Card highlights both issues of concern and potential solutions. Most existing power lines were constructed in the 1950s and 1960s with a 50-year life expectancy, meaning they were not designed to meet today’s significant demand or the evolving need to integrate distributed energy resources. While projections for energy consumption indicate only modest increases between 2015 and 2040,[1] the country still faces significant challenges in ensuring energy is available where it is needed, including transmitting energy from renewable sources to population centers. We cannot build a new wind farm in Kansas and expect the power to just magically appear in New York.

Aging lines and equipment in America’s multiple power grids are operating well beyond their designed maximum operating temperature and peak load, and congestion creates transmission constraints for delivering power from remote generation sites to areas of demand, also affecting reliability and cost of service.[2] NERC’s standards for tree clearance and vegetation only go so far when confronting increasing extreme weather events and exposure to human threats. And just as one closed road causes traffic jams, one power line outage can affect transmission and distribution to millions. Because of a lack of storage and near constant demand, the interruption of any energy system is immediately felt by the user.

While there are certainly more potholes in America’s roads than there are estimated power outages each year, loss of electric power or gas flow through a major pipeline causes a ripple effect on Americans’ daily lives and the economy. The U.S. energy system is the critical infrastructure that keeps America’s lights on, transportation moving and information flowing. Yet the current system in many parts of the country is not adequately resilient and efforts to change that through investment and improvement are highly politicized, often caught up in larger debates about climate change, fuels and national security.

As part of the Report Card, ASCE also commissioned an independent economic analysis of the investment needs and consequences across 10 sectors of infrastructure, including electricity, by a well-respected economic research group. The series, titled “Failure to Act,” was first released in 2011 but was updated in 2016.[3] [4] The 2016 study examines the investment needs, projected funding and remaining gap for building new infrastructure as well as maintaining or rebuilding existing infrastructure. The analysis also presumes the mix of generation technologies and sources continues to evolve, resulting in new efficiencies and approaches for meeting demand. The study concluded that in electricity, while the investment gap totals $177 billion between 2016 and 2025, more than 80% of the total infrastructure investment needs are projected to be funded, thanks in no small part to the significant involvement of the private sector in the nation’s energy systems.

No American who has experienced an extended electrical outage, lost appliances because of a power surge or seen downed wires in their neighborhood would grade our electric infrastructure an A, nor do the engineers who design, build and desire to maintain that infrastructure day in and day out.

Chuck Hookham, P.E., M.ASCE, is director of NBD services at CMS Energy, a large regulated electric/gas utility and non-regulated developer of energy projects, headquartered in Jackson, Mich. He has more than 35 years of experience in power generation, transmission and distribution, natural gas and oil pipelines and refineries, and infrastructure systems, and is a member of the ASCE Committee on America’s Infrastructure, which prepared the 2017 Infrastructure Report Card.

Otto J. Lynch, P.E., F.ASCE, F.SEI, is vice president of Power Line Systems Inc. in Nixa, Mo. For more than 28 years, he has participated in the design and construction of numerous high-voltage transmission line projects around the world and was a pioneer in the use of LiDAR in the transmission line industry. He is a member of the ASCE Committee on America’s Infrastructure, which prepared the 2017 Infrastructure Report Card.

Adrienne Nikolic, P.E., M.ASCE, is an energy and utilities consultant based in Philadelphia, Pa. She is responsible for assisting energy and utility clients with the management of projects that modernize the grid, and is a member of the ASCE Committee on America’s Infrastructure, which prepared the 2017 Infrastructure Report Card.

[1] U.S. Energy Information Administration Annual Energy Outlook 2017. https://www.eia.gov/forecasts/aeo/executive_summary.cfm

[2] U.S. Department of Energy. Quadrennial Energy Review Energy Transmission, Storage, and Distribution Infrastructure. 2015.

http://energy.gov/sites/prod/files/2015/08/f25/QER%20Summary%20for%20Policymakers%20April%202015.pdf

[3] American Society of Civil Engineers. Failure to Act: The Economic Impact of Current Investment Trends in Electricity Infrastructure. 2011. http://www.asce.org/electricity_report/

[4] American Society of Civil Engineers. Failure to Act. 2016. http://www.infrastructurereportcard.org/the-impact/failure-to-act-report/

April 18, 2017

Court Rejects FERC ROE Order for New England

By Rich Heidorn Jr.

An appellate court on Friday overturned FERC’s 2014 order setting the base return on equity for a group of New England transmission owners at 10.57%, saying the commission failed to meet its burden of proof in declaring the existing 11.14% rate unjust and unreasonable.

“Because FERC failed to articulate a satisfactory explanation for its orders, we grant the petitions for review,” a three-judge D.C. Circuit Court of Appeals panel ruled in an opinion written by Senior Judge David B. Sentelle. The court vacated the order and remanded the case to the commission for additional proceedings (15-1118).

It is unclear how the court’s ruling will ultimately affect the rates for the TOs, which include Emera Maine, Northeast Utilities, Central Maine Power, National Grid and NextEra Energy.

Much may depend on who is appointed by President Trump to fill the vacancies that have left FERC with only two commissioners, one short of a quorum. “Under a new FERC composition, nominally under a ‘pro-infrastructure’ administration, there is potential for the environment to be more favorable for transmission ROEs,” UBS Securities analyst Julien Dumoulin-Smith said in a research note Monday.

But the court’s ruling provided ammunition for state officials seeking a lower rate, saying FERC’s analysis was “unclear.”

Attorney David Raskin, who argued the case for the TOs, referred questions to Emera, which did not respond to requests for comment. A spokesperson for the Connecticut attorney general’s office said it was reviewing the decision and declined further comment. FERC also declined to comment.

2014 Ruling

In the 2014 ruling, the commission voted 4-0 to change the way it calculates ROEs for electric utilities, moving to a two-step discounted cash flow (DCF) process it has long used for natural gas and oil pipelines that incorporates long-term growth rates.

But the commission split 3-1 over its first application of the new formula, tentatively setting the ROE for the New England TOs at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range (EL11-66-001). (See FERC Splits over ROE.)

The commission’s ruling resulted from a complaint filed in 2011 by New England state officials and others who contended the 11.14% base ROE was unreasonable because interest rates had fallen since the commission established it in 2006.

Both the New England TOs and state officials representing customers appealed FERC’s order to the D.C. Circuit, saying the commission had failed to meet the requirements under FPA Section 206 for setting a new ROE. The appeals followed a second FERC order rejecting rehearing requests.

The TOs and customers did not challenge FERC’s use of the two-step methodology or the resulting zone of reasonableness, which the commission tentatively set as 7.03 to 11.74%, a reduction from the 2006 ruling that set the range at 7.3 to 13.1%. Rather, they challenged FERC’s setting of the base ROE within the new zone.

The TOs said the order should be vacated because it failed to find that the existing ROE was unjust and unreasonable before setting a new ROE. The states contended that FERC arbitrarily placed the new ROE at the midpoint of the upper half of the zone of reasonableness.

Section 205 vs. Section 206

FERC’s authority to set transmission rates is governed by Sections 205 and 206 of the Federal Power Act.

TOs may seek a rate change under Section 205 and are not required to show that a previous rate was unlawful. But the states’ challenge that prompted the 2014 order was filed under Section 206, which requires FERC to determine whether an existing rate is unjust and unreasonable before it can impose a new rate. “The burden of demonstrating that the existing ROE is unlawful is on FERC or the complainant, not the utility,” the court noted.

Instead of first finding that their base ROE was unjust and unreasonable, FERC decided that 10.57% was the just and reasonable base ROE and that the existing 11.14% ROE was unlawful as a result, the TOs said.

FERC contended its determination of a new just and reasonable base ROE was “sufficient” by itself to prove that the existing ROE was unjust and unreasonable.

The court disagreed. “Because it was a Section 206 proceeding, rather than a Section 205 proceeding, FERC bore the burden of making an explicit finding that the existing ROE was unlawful before it was authorized to set a new lawful ROE. FERC, however, never actually explained how the existing ROE was unjust and unreasonable,” the court said.

“Although we defer to FERC’s expertise in ratemaking cases, the commission’s decision must actually be the result of reasoned decision-making to receive that deference. Without further explanation, a bare conclusion that an existing rate is ‘unjust and unreasonable’ is nothing more than a talismanic phrase that does not advance reasoned decision-making.”

ROE Incentives

Because FERC failed to meet its dual burden under Section 206, the court said it did not need to rule on the TOs’ complaints that the commission’s ruling also violated their due process rights by failing to put them on notice that it would reconsider previously approved ROE incentives in addition to the base rate.

The states challenged only the TOs’ base ROE, and not the incentives. But because the ruling reduced the upper end of the zone of reasonableness from 13.1% to 11.74%, FERC noted that the TOs’ total ROE including incentives must remain within the zone. Although the commission chose a higher position within the range, the TOs’ ROE was reduced because the new formula reduced the top end of the zone.

Where in the Zone?

In setting the ROE at the 75th percentile of the zone, the commission majority sided with the TOs and rejected arguments by FERC trial staff and consumer representatives, who had argued for continuing the commission’s traditional use of the zone’s midpoint, which would have put the ROE at 9.39%.

Commissioners Cheryl LaFleur, Philip Moeller and Tony Clark said the change was justified because of the unusually low interest rates at the time; it had “less confidence” that “a mechanical application” of the midpoint of the DCF zone would result in an ROE high enough to allow the TOs to attract investment capital. Commissioner John Norris dissented, saying there was insufficient evidence to support setting the rate so high.

The court questioned the FERC majority’s reasoning.

“On the one hand, it argued that the alternative analyses supported its decision to place the base ROE above the midpoint, but on the other hand, it stressed that none of these analyses were used to select the 10.57% base ROE.”

FERC said “alternative benchmark methodologies” and additional evidence supported its conclusion that the midpoint would be too low. But the court said “none of the analyses necessarily suggested that a 10.57% ROE was a just and reasonable base ROE. Thus, the only conclusion FERC drew from these analyses was that transmission owners were entitled to an ROE somewhere above the 9.39% midpoint.”

The court noted that 10.57% was higher than 35 of the 38 data points FERC used to construct its DCF zone of reasonableness. It also said 89% of the state commission-authorized ROEs that FERC consulted were below 10.57%.

FERC also cited three alternative benchmark methodologies as “informative.” The risk premium analysis supported a base ROE between 10.7 and 10.8%; the Capital Asset Pricing Model produced a midpoint of 10.4%; and the expected earnings analysis had a midpoint of 12.1%.

“It is not our job to tell FERC what the ‘correct’ ROE is for transmission owners, but it is our duty to ensure that FERC’s decision is ‘the product of reasoned decision-making,’” the court said. “While the evidence in this case may have supported an upward adjustment from the midpoint of the zone of reasonableness, FERC failed to provide any reasoned basis for selecting 10.57% as the new base ROE.”

Michael Kuser contributed to this article.

April 17, 2017

Gas, Solar, Efficiency Nudge Coal in Arizona Public Service IRP

By Robert Mullin

Arizona Public Service expects to meet its future energy needs through increased use of natural gas, solar and efficiency measures, while at the same time reducing its reliance on coal-fired generation, according to the company’s 15-year integrated resource plan.

The IRP filed with the Arizona Corporation Commission predicts the utility will face a deepening “duck curve” — such as that already witnessed in California — as households within its service territory ramp up adoption of non-curtailable rooftop solar resources.

Still, APS sees a continued, if reduced, role for its 1,146-MW Palo Verde nuclear plant located near Phoenix, which the company refers to as the country’s “largest carbon-free resource.”

Palo Verde Nuclear Generation Station | *APS*

The IRP calls for APS to rely on solar resources and energy efficiency to meet 50% of projected demand growth in its service territory by 2032, when the utility’s peak capacity requirements are expected to reach 13,000 MW, a 61% increase from the current 8,086 MW. The plan assumes that Arizona’s population will grow to more than 9 million from around 6.9 million today, adding 550,000 customers to the utility’s service area. The state’s Office of Economic Opportunity population projection falls short of APS’ 2032 estimate at just less than 8.8 million.

“We do have some concerns with [APS’s] numbers, but haven’t come to any conclusions yet,” Ken Wilson, an engineering fellow with Western Resource Advocates, told RTO Insider. Wilson noted that he’s participated in several preliminary workshops in which the utility presented its projections for load growth.

To achieve its goal of using renewables and efficiency to address half of that expected future growth, APS has proposed what it calls a “flexible resource portfolio,” that reduces carbon emissions through “select coal reductions,” more demand-side management and “a prudent level of energy storage,” while continuing to add renewables and operate Palo Verde.

Over the planning period, natural gas generation is expected to increase from 26% to 33% of the utility’s energy mix, while utility-scale renewables grow from 12% to 18%.

The utility also expects to offset peak load with an additional 979 MW of demand-side resources, which includes demand response and energy efficiency.

Coal-fired capacity would decline by 702 MW (42%) to 970 MW, accounting for 11% of the energy mix, down from 21% today. Output from Palo Verde is slated to hold steady, but the plant’s share of the mix would drop from 25% to 17%.

arizona public service gas solar coal — | *APS*

Market purchases are forecast to rise from 3% to 8% as the company retires coal and rolls off existing power contracts.

“APS will continue to pursue opportunities to increase operating efficiency and save customers money, such as participating in the CAISO Energy Imbalance Market and purchasing excess energy from short-term markets at low or negative (i.e., paid to take) prices,” the company said in a statement.

APS estimates that its CO₂ emissions and water consumption per unit of electricity will decline by 23% and 29%, respectively.

“Overall, our energy mix is increasingly cleaner, and we are adding more quick-starting power sources to integrate our growing solar energy resources and emerging technologies,” said Tammy McLeod, APS vice president of resource management.

Key among those technologies is energy storage, the deployment of which is expected to climb from 4 MW to 507 MW over the next 15 years.

The IRP points to the adoption of rooftop solar as “one of the single most defining factors in western energy markets today,” given its tendency to displace the output of other resources, create volatility in wholesale power prices and increase the need for fast-ramping natural gas plants and resources serving local load pockets.

APS expects rooftop installations within its territory to nearly double by 2032 to 4,998 MW, precipitating a deepening of a duck curve that could push “net loads” — the portion of system load served by non-variable resources — to as low as 500 MW, which will create ramping requirements of between 4,000 and 5,000 MW.

In response, the company plans to upgrade its operational flexibility, including the modernization of its Ocotillo Power Plant with five quick-start natural gas-fired units. APS also plans to invest in technologies that increase real-time visibility into the utility’s distribution system and implement a new Demand Response, Energy Storage, Load Management program to help residential customers manage energy use.

“Increasing renewable resources, energy efficiency and energy technologies, supported with highly responsive resources such as natural gas generation, will enable APS to deliver cleaner, reliable and reasonably priced electricity,” McLeod said.

April 17, 2017

SPP Z2 Panel Sees ILTCRs as Cure to ‘Mess of Complexity’

By Tom Kleckner

TULSA, Okla. — SPP’s Z2 Task Force last week conducted a series of votes to determine potential alternatives to the RTO’s cumbersome crediting system for transmission upgrades in time for a July deadline.

The group’s consensus is that incremental long-term congestion rights (ILTCRs) modeled after the RTO’s LTCR process and some modifications to the Z2 process are the best options for moving forward.

“We’re separating the must-haves from the nice-to-haves,” Kansas City Power & Light’s Denise Buffington, the task force’s chair, told the Markets and Operations Policy Committee on April 12.

AEP’s Richard Ross (left), KCP&L’s Denise Buffington (right) make their cases over AEP’s Bruce Rew. | © *RTO Insider*

Under Attachment Z2 of the RTO’s Tariff, members are assigned financial credits and obligations for sponsored upgrades. The task force is trying to simplify the process — which resulted in eight years of incorrectly applied credits — while still meeting FERC requirements.

It hasn’t been easy.

“It’s a mess of complexity,” SPP’s Charles Locke said, referring to three different funding mechanisms for the Z2 process: base plan, directly assigned costs and point-to-point clawbacks under various Tariff schedules.

“I’m not interested in coming to another meeting with more data and more proposals, and [having] another discussion on why we don’t like the process,” Buffington said, keeping the group on task during its meeting before the MOPC session.

SPP’s Charles Cates, Midwest Regulatory Consulting’s Dennis Reed listen to the discussion. | © *RTO Insider*

After “spirited discussion,” as Buffington described it to the MOPC, the task force approved:

Replacing the existing Z2 process with ILTCRs for all three upgrade types (sponsored, transmission service and generator interconnections). Doing so would require a secondary market to trade the ILTCRs and make them fully transferable, following examples set by MISO, PJM and other RTOs. Staff proposed using a modified ILTCR process for generator interconnection upgrades and the existing process for the other two upgrades but said it would need further study and software changes costing hundreds of thousands to implement all three categories.
A rate allocation similar to the Tariff’s schedules 11 and 13 for all three categories, with a limited roll-in of the facilities’ cost, depending on the extent to which it is used for subsequent transmission service. The proposal is focused on compensating service-upgrade sponsors, but it could be used for the other two categories.
Consideration of a standard credit payment rate that would put point-to-point payment obligations on par with network obligations.
Eliminating credits for short-term transmission service by decoupling a short-term transfer tool from the credit stacking system. Short-term impacts will no longer be “stacked” to determine when a creditable upgrade becomes reverse creditable. Staff assumes “fairly minimal” changes with this option and said it could take as little as two months to implement.
Eliminating credits for non-capacity upgrades.

The task force has scheduled two additional meetings to make a final decision and put together a final recommendation for the MOPC and Board of Directors meetings in July.

April 17, 2017

FERC: Gas Continued to Dominate in 2016

By Michael Brooks

Record warmth, combined with one of the largest increases in pipeline capacity in U.S. history, led to record-low gas prices last year, FERC said in its annual State of the Markets Report, released Thursday.

The 2015-2016 winter was the warmest on record for the continental U.S., with temperatures nearly 5 degrees above the 20th century average, according to the National Oceanic and Atmospheric Administration.

“Above average temperatures in the 2015-2016 winter limited natural gas demand during the first three months of the year, leading to robust storage inventories at the start of the 2016 injection season in April and reduced demand for storage injections through the summer,” FERC said. “Prices fell to record lows in the first half of 2016, before climbing thorough the second half of the year driven by steady domestic demand, rising exports and a drop in production.”

ferc state of the markets report natural gas — | *FERC State of the Markets 2016*

Henry Hub prices averaged $2.48/MMBtu, the lowest in 20 years and a 5% decrease from 2015. While prices fell across the country in 2016, the Northeast saw the most dramatic decreases, with New York City prices falling 42%. The region, however, saw a spike in prices last month. (See related story, Gas, LMPs Rebound in NY, New England in March.)

The low prices are made even more notable by the fall in supply. Gas production fell 2.5% last year, averaging 72.3 Bcfd, as overall domestic demand only rose 1% to 75.6 Bcfd. This was the first year-over-year drop in production since 2005, FERC said. However, the commission expects that production will rebound this year, “driven by a projected 26% increase in oil and gas exploration and production investment,” it said.

Prices will also remain low this year, the report said, because of the amount of new pipeline capacity. 2016 saw 7.1 Bcf go into service, and more projects are expected this year, with three into Mexico. Exports to the country grew 24% to 3.6 Bcfd, marking the sixth year in a row they have increased.

Storage withdrawals at the beginning of the year totaled 1.8 Tcf, the lowest in four years, and as a result, inventories stood at 2.5 Tcf in April, a record high. Inventories set another record at the end of the injection season as well, with 4.047 Tcf in storage in November.

Because winter 2016/17 was not quite as warm as 2015/16, gas demand from residential and commercial increased by 12% in December, compared to the same month in 2015. However, this winter made headlines for its brevity, with February 2017 being the second-warmest February on record. Last month, the Energy Information Administration reported the first-ever gas injection in February.

Gas Overtakes Coal; Renewables Continue Gains

While gas demand from the residential and commercial sectors fell 5.1%, this was partially offset by a 4% increase from power generators. 2016 was a landmark: While gas’ growth slowed (demand increased by 17% in 2015), it became the primary source of electricity generation nationally in 2016, the first time ever on an annual basis, according to EIA data. Gas generated 34% of U.S. electricity, compared to 30% from coal.

The U.S. added more than 27 GW of generating capacity in 2016, according to EIA. About a third of this were new natural gas plants, while about 10 GW of coal plants retired.

Most of the remaining additions were utility-scale renewable resources. The U.S. added 8.7 GW of wind and 7.7 GW of solar in 2016, according to EIA. The commission said renewables were buoyed by the extensions of the production and investment tax credits, as well as several increases in state renewable portfolio standards.

Additionally, despite the retirement of the 478-MW Fort Calhoun nuclear plant in October, the completion of Watts Bar Unit 2 that same month led to a slight net increase for nuclear capacity. FERC expects the increase to be short-lived, however, as numerous plants are expected to retire in the next few years. The fate of two under-construction plants in the Southeast are in doubt following the bankruptcy of Westinghouse Electric last month.

Net Metering Contributing to Low Electricity Demand, Prices

Thanks largely to cheap gas, power prices were down across most of the country, with PJM recording the lowest LMPs since the RTO’s formation in 1999. (See PJM Monitor Concerned About State Subsidies.) Like gas prices, New York and New England saw the biggest drop.

Total electricity sales fell 13% from 2015, even as the U.S. economy experienced steady growth. FERC attributed this to the warm winter and increased energy efficiency.

The commission also noted that net metering from rooftop solar is reducing demand for wholesale power. According to EIA, distributed solar capacity increased by 3.4 GW last year.

“Although net-metered projects largely participate in retail markets, their aggregate impact has begun to affect wholesale markets with large penetration of distributed solar projects,” FERC said. “These impacts can largely be seen as a functional reduction on demand from the RTO/ISO perspective, with subsequent shifting of system load curves.”

April 17, 2017

MISO IMM Recommends Tighter Rules for Constrained Areas

By Amanda Durish Cook

MISO’s Independent Market Monitor is again recommending the RTO expand mitigation measures on narrowly constrained areas by creating a new definition aimed at periods of temporary congestion.

At an April 13 Market Subcommittee meeting, Monitor staffer Michael Wander said the RTO should seek FERC permission to create dynamic narrowly constrained areas (NCAs) to address short-lived congestion and associated market power.

MISO currently has five NCAs with conduct thresholds — prices that indicate potential exercises of market power — that range between $22.31 and $100/MWh. NCAs are defined by FERC as chronically constrained where constraints that can limit competition bind for more than 500 hours annually. They can be defined in advance and are subject to tighter market mitigation thresholds than broad constrained areas.

MISO’s Independent Market Monitor is again recommending the RTO expand mitigation measures on narrowly constrained areas by creating a new definition aimed at periods of temporary congestion.

The Monitor says there are areas that do not meet the 500-hour trigger that also need to be covered by stricter thresholds, as they are “severely constrained areas with one or more pivotal suppliers.”

The dynamic NCA would be declared when conduct has occurred that would warrant mitigation on a non-NCA constraint, and that constraint has bound in 15% or more hours over at least five days. The new category, which would set a conduct threshold at $25/MWh, should only be used in “network conditions … that create substantial market power,” the Monitor said.

The Monitor first recommended creating dynamic NCAs in its 2012 State of the Market Report.

“We’re proposing to move on this as quickly as possible. I think we’ll propose Tariff language to stakeholders, and we have affidavits at the ready,” Wander said.

To create the category, MISO would have to expand its Module D mitigation provisions in the Tariff. Wander said moving the threshold will not require changes to the RTO’s automated mitigation procedures.

Dhiman Chatterjee, MISO director of market evaluation and design, said the RTO is “more or less on the same page” with the Monitor but needs time to review the recommendation.

Had the dynamic NCA definition been in place in 2015 and 2016, it would have been implemented 25 times for an average nine days each, Wander said. The impacts would have ranged from an average of $6.50/MWh to $424/MWh, with the highest price impact at $1,400/MWh. Wander said the simulation showed that dynamic NCAs would have occurred most frequently in MISO’s South and Central regions.

April 17, 2017

MISO, IMM Differ over Scarcity Pricing Changes

By Amanda Durish Cook

MISO’s Independent Market Monitor says the RTO isn’t going far enough in proposing changes to comply with FERC’s new energy offer cap rules.

MISO IMM value of lost load — Hansen | © *RTO Insider*

Chuck Hansen, MISO senior market engineer, told the April 13 Market Subcommittee meeting that the RTO will propose only “minimal” changes to its operating reserve demand curve (ORDC) in a filing planned for next month to comply with FERC Order 831, which requires the use of a $1,000/MWh soft cap and $2,000/MWh hard cap by winter 2017/18. MISO says the ORDC also must be changed because of new NERC reliability rules. (See MISO Contemplates Market Design Changes from FERC Offer Cap Rule.)

Monitor David Patton, however, told the committee that MISO should make broader changes, including an immediate increase in its maximum value of lost load (VoLL) calculation.

MISO’s Step-Based Curve

MISO’s current ORDC is step-based, dropping sharply from a $3,500/MWh maximum VoLL when less than 4% of the requirement level has cleared, to $1,100/MWh when more than 4% of the requirement clears. It then drops vertically to $200/MWh when 96% or more of the requirement is satisfied.

Under MISO’s proposal, the new curve would begin at $3,300/MWh, dropping to $2,100/MWh when the RTO clears 8% of its requirement level, reflective of “extreme scarcity conditions,” Hansen said. At 89%, the level falls to $1,100, remaining there until 96% or more of the requirement is cleared, when the curve flattens at $200.

Even as the top of the ORDC inches toward the maximum VoLL — currently the $3,500/MWh limit set in 2005 — Hansen said MISO won’t recommend VoLL changes in its FERC filing. He acknowledged, however, that the maximum will have to be redone in the “near future.”

“We’re going to move forward with [refreshing the VoLL] subject to budget limits. We’ve got a lot of things going on right now, but assessing VoLL is not a trivial matter,” MISO Executive Director of Market Design Jeff Bladen said.

MISO’s deadline for filing the proposed changes is May 8. “We should be able to achieve that if everything goes as planned,” Hansen said.

Order 831 caps incremental energy offers at the higher of $1,000/MWh or a resource’s cost-based energy offer, with $2,000/MWh being the maximum bid. (See New FERC Rule Will Double RTO Offer Caps.)

MISO said its proposal won the broadest support from stakeholders of four options considered.

Patton Seeks Increase in VoLL

But Patton is recommending the RTO make immediate changes to its VoLL limit and change its ORDC calculation to a sloped curve that he contends would better price shortages. Patton said a VoLL cap of $9,000/MWh is reasonable based on past studies. The Monitor would set a VoLL of $1,000/MWh to reflect the demand curves for spinning reserves and regulation, and high marginal energy costs resulting from congestion.

He pointed to PJM, which currently prices shortages as high as $6,000/MWh (based on the sum of the shortage pricing and capacity performance settlements). If MISO does not increase its VoLL, Patton said, it will result in inefficient imports and exports with PJM when both markets are tight.

Patton says MISO’s proposal fails to address problems with the current curve, which he says overstates the reliability risks for small shortages and understates them for more severe ones. “The steep portion of the ORDC is based on inaccurate loss-of-load estimates” that incorrectly model the loss of only one unit at a time and do not accurately capture wind forecast errors, Patton said.

The Monitor said the curve should reflect the expected VoLL through a calculation of the probability of losing load multiplied by the net value of lost load, resulting in a smoother, more “economic” curve than MISO’s current step-based pricing.

FERC Guidance Needed

Patton said it would be “helpful” if FERC would offer guidance for creating operating demand curves. “They’re set in crude, step-wise curves,” he said. An economic curve will reflect the value of reliability and “allow prices to rise efficiently as operating reserve shortages increase.”

Patton maintains that the current curve’s steep jump between $1,100/MWh and $200/MWh results in “volatile pricing” by offline resources that set prices in extended locational marginal pricing. “The shortage pricing under the economic ORDC will track the escalating risk of losing load,” Patton said. “In the range where most shortages occur, the economic ORDC is sometimes higher and sometimes lower than the current curve so it should not substantially increase consumer costs for these shortages.”

Bladen said there’s “almost certainly improvements to be made” to the ORDC, but MISO first must perform its own studies and move the issue through the stakeholder process before it proposes further improvements.

April 17, 2017

MISO Resource Adequacy Subcommittee Briefs

MISO stakeholders will decide in an email vote whether it’s worth debating the cost allocation for holders of firm transmission service reservations of more than 1,000 MW between MISO Midwest and South.

The Load-Serving Entities sector presented a motion to the Resource Adequacy Subcommittee on Wednesday asking that MISO drop the issue, which is an outgrowth of the RTO’s settlement over the use of SPP’s transmission for North-South transfers. The LSEs said changing the cost allocation of payments to SPP would not provide significant benefits to MISO.

Kevin Murray, representing the Coalition of MISO Customers, asked that a vote on the motion be tabled until FERC acts on the uncontested settlement for cost allocation among MISO members filed in August (ER14-1736, et al.), but stakeholders overwhelmingly rejected tabling the motion, 36-2. In the settlement filing, MISO has proposed allocating a declining percentage of the costs to reimburse SPP through a load ratio calculation and an increasing amount through a flow-based benefits methodology.

Keith Berry of the Arkansas Public Service Commission pointed out FERC may not act for quite a while because the commission has been short of a quorum since former Chairman Norman Bay’s resignation in February. President Trump has not nominated any replacements to fill the commission’s three open seats.

After considerable debate, stakeholders agreed to decide the issue via email. Ballots are due April 19.

Some stakeholders said firm reservations undoubtedly diminished the 2016/17’s Planning Resource Auction’s transfer capability between the RTO’s Midwest and South regions from 1,000 MW to 876 MW, increasing clearing prices.

Last month, some stakeholders questioned whether continuing the debate over the cost allocation was worth the effort. The 1,000-MW-plus usage of the transfer path is only relevant in the 2018/19 planning year, when firm reservations were granted in excess of 1,000 MW. (See “MISO Examines Single Year of MISO-SPP Settlement Allocation,” MISO Resource Adequacy Subcommittee Briefs.)

Any change would affect no more than 304 MW, because the potential TSRs over the North-South path for the year total 1,304 MW, the LSEs said.

MISO is currently in the fourth year of its settlement agreement with SPP over flows of more than 1,000 MW using SPP transmission to ferry energy between MISO Midwest and MISO South.

MISO Manager of Resource Adequacy Coordination Laura Rauch said the RTO and stakeholders have to reach a decision by November, filing either a cost allocation change or a notice explaining it would not pursue the issue. RASC Chair Chris Plante said the Regional Expansion Criteria and Benefits Working Group could be charged with working out the details if stakeholders decide to pursue a cost allocation change.

Next April, MISO stakeholders will tackle a related issue, deciding if and how to allocate costs to benefiting entities if the RTO raises the amount of capacity that can be transferred between the South and Midwest sub-regions to more than 1,000 MW in capacity auctions after April 2018.

MISO Still Tweaking OMS-MISO Survey Format

MISO is still tinkering with the format of its annual resource adequacy survey with the Organization of MISO States.

The RTO is proposing a “floating” format in which committed retirements and additions with signed interconnection agreements are left out of the bar graphs and the survey instead focuses on the range of possibilities from planned additions and potential retirements.

miso resource adequacy subcommittee cost allocation — 2016 OMS-MISO Survey results with 35% DPP projects in floating format | *MISO*

“People tend to gravitate toward the low end of the range. We’re really not trying to point people to the low end of the range or the high end of the range,” RASC Chair Shawn McFarlane said.

Survey results are expected in June. MISO plans to add a 35% share of projects in the definitive planning phase of the interconnection queue into survey results, although stakeholders have said the completion estimate is too low. (See Differences Persist over OMS-MISO Survey Improvements.) Incorporating the 35% calculation would have shifted 2016 results from a possible 15.9 to 17.4% planning reserve margin range to 15.9 to 19.1%. MISO requires a 15.2% reserve margin.

Rauch said MISO will continue to work on the survey format even after results are released in late spring. “We have had it evolve over the years with incremental changes,” said Rauch, pointing out that the RTO now focuses on the first five years of survey, rather than the full 10 years. It also shares data for each local resource zone while reporting inter-zonal transfers.

Stakeholders asked if MISO considers other variables, including external resources and wind at full capacity. Rauch said the RTO does consider transfers from other balancing authorities when calculating survey results.

— Amanda Durish Cook