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.
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.
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+.
Huntoon
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.
[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.
[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.
[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/
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.
| Avangrid
“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.
| FERC
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.”
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%.
| 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.
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.
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.
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.
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 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.
| FERC State of the Markets 2016
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.
| FERC State of the Markets 2016
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.”
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.
“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.
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.
| Potomac Economics
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.
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.
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.
All 135 GW worth of capacity procured across 10 local resource zones in MISO’s fifth annual Planning Resource Auction cleared at $1.50/MW-day, a vast departure from the regional disparities of the last two years, when prices rose as high as $150.
MISO said the results for planning year 2017/18, which begins June 1, are reflective of new supply and lower demand in the Midwest.
“The 2017-18 auction results reflect a net regional increase in supply compared to last year’s results,” said Richard Doying, MISO executive vice president of operations. “Even as the generation fleet continues to evolve, the level of available resources positions the region well for reliable operations in the coming year.”
Because there were no binding constraints between the zones, all zones’ prices were set by an offer submitted by a resource in Zone 1, which encompasses parts of Wisconsin, Minnesota and the Dakotas, Doying said.
The year’s “uneventful” results were a function of more supply and less demand, and the lack of constraints. “When you combine those two, you get lower prices and uniform prices. … It doesn’t take much to have a significant impact on the clearing results,” he said during an April 14 press conference.
Doying also said results weren’t surprising given that even a small uptick in supply or a small reduction in demand can drop prices.
Capacity Needs Drop by 730 MW
MISO experienced an overall 730-MW decrease in capacity requirements, resulting from a roughly 1,000-MW decrease in MISO Midwest’s requirement and an approximate 300-MW increase in MISO South, indicative of regional economies, Doying said.
At an April 14 stakeholder conference, energy attorney Valerie Green of Michael Best & Friedrich asked if MISO had an explanation for the decline in load. MISO Manager of Resource Adequacy John Harmon said economic slowdowns were consistent across zones that experienced load declines.
Doying said this year’s offers included more demand, energy efficiency, solar and wind resources than the 2016/17 planning year auction. Auction results were reviewed and certified by MISO’s Market Monitor; no mitigation was required.
The single clearing price is in stark contrast to the RTO’s last two PRAs. In the 2016/17 auction, MISO South cleared uniformly at $2.99/MW-day and almost all of MISO Midwest cleared at $72/MW-day, with Zone 1 the lone outlier at $19.72/MW-day. (See MISO’s 4th Capacity Auction Results in Disparity.) MISO said last year’s disparate results were a product of retirements and capacity exports. This year’s clearing price also represents a hundred-fold decrease from the $150/MW-day price in Illinois’ Zone 4 in the 2015/16 planning year auction.
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Illinois Clean Jobs Coalition spokesman Billy Weinberg said the 2017/18 auction results are evidence that market forces are favoring energy efficiency and more affordable renewables. “Now is the time to begin planning for new investments and jobs in Central and Southern Illinois in cleaner technologies like energy efficiency, wind and solar energy that grow cheaper by the day and improve public health,” he said.
MISO also said the prices were a result of the improved transfer capability between zones. MISO’s South-to-Midwest export constraint increased from 876 MW last year to 1,500 MW this year; the Midwest-to-South limit increased from 2,794 MW to 3,000 MW. (See MISO to Use Same Sub-Regional Limit Rules for 2017/18 PRA.)
This year, the RTO’s maximum offer using the cost of new entry ranged from $246/MW-day for Zone 10 in Mississippi to $265/MW-day for Zone 5 in eastern Missouri.
In March, MISO predicted that all local resource zones would have enough capacity to meet their individual clearing requirements, with 172 GW worth of total installed capacity easily meeting the RTO’s 135-GW planning reserve margin requirement. (See “Preliminary PRA Data Show Capacity Excess,” MISO Resource Adequacy Subcommittee Briefs.)
Harmon said auction results will be presented to stakeholders in a more detailed presentation at the May 10 Resource Adequacy Subcommittee meeting.
In a research note Friday, UBS Securities analysts Julien Dumoulin-Smith and Jerimiah Booream called the results “a material disappointment for MISO, sending prices back to their historic lows of 2012 and 2013. … This will prove difficult to shift out of given the impacts from [the Mercury and Air Toxics Standards] and other environmental regulations that drove the improvements in prior periods.”
UBS had predicted prices would clear no lower than $12/MW-day. The analysts said prices would have been closer to $10/MW-day based on the lower demand but that the offer curve was also “flatter” because of Illinois’ approval of zero-emission credits for Exelon’s Clinton nuclear plant, which left the company less concerned with maximizing its capacity revenue. “This was the decisive factor in holding prices lower,” they wrote.
Same Auction Process
The auction was unchanged from its usual format, despite MISO’s attempt at a redesign that would have bifurcated the capacity market by holding a forward auction for competitive load three years prior to the prompt PRA. In February, MISO abandoned the changes after a curt FERC rejection. (See MISO Won’t Seek Rehearing on Auction Redesign.)
Doying said MISO has “other priorities” than reviving the Competitive Retail Solution. He said the RTO will continue a discussion about resource adequacy in Michigan and Illinois.
Exelon’s decision to keep its Quad Cities nuclear plant operating — thanks to Illinois’ approval of zero-emission credits to provide the plant additional revenue — has eased some of MISO’s concern, Doying said.
External Zones, Seasonal Classification
That does not mean MISO is dropping plans to improve the PRA. While a possible two-season classification is on ice for the remainder of 2017, the RTO is currently navigating the stakeholder process on creating external capacity pricing zones.
“Industry forces continue to indicate significant shifts in the fleet,” Doying said. “MISO will continue to address seasonal and locational issues with our stakeholders while ensuring that market signals provide incentives for investment where and when they are needed.”
At an April 12 RASC meeting, MISO’s Laura Rauch asked stakeholders how different classes of external resources should be treated. She presented stakeholders with examples of pseudo-tied resources, border resources and coordinating owners such as Manitoba Hydro. She also asked about contracts signed before the formation of the MISO market in 1998 or FERC’s 2012 approval of the PRA construct.
“What is the best method to recognize the contracts of existing resources?” Rauch asked stakeholders.
MISO is also asking stakeholders what rules should dictate external zone pricing. The RTO has proposed that the external zone price be based on the sink of the external resource.
Last month, the Monitor suggested pricing be based on balancing authority boundaries, with resources connected to both sides of Midwest-North constraint receiving a blended price. (See “IMM Offers Own PRA External Zone Design,” MISO Resource Adequacy Subcommittee Briefs.) Rauch said MISO will use stakeholder input to draft Tariff language and address the Monitor’s proposal at the May RASC meeting. Rauch said MISO staff is still evaluating the proposal.
Illinois Municipal Electric Agency’s Rakesh Kothakapu said MISO needed to be careful with pricing, especially considering if external zones continue to be priced low while supply continues to tighten. “We don’t want to end up in a situation where we price them lower even when it has nothing to do with a constraint,” he said.
A seasonal auction classification is beginning to look less certain.
“There’s a general thought that stakeholders aren’t as interested in a seasonal construct as they once were. The informal feedback I’m receiving is along those lines,” RASC Chair Chris Plante said.
