VALLEY FORGE, Pa. — FERC did not act on PJM’s proposed changes to its shortage pricing, so revisions for how to handle transient shortages will go into effect May 11 as planned, Manager of Real-time Market Operations Lisa Morelli told the Market Implementation Committee on Thursday. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
The curve step changes are still on track to be implemented on July 1, but it’s unclear whether that will definitely happen.
“There’s unfortunately uncertainty [about] a lot of what’s happening at FERC right now,” PJM attorney Steve Shparber said. “We will keep going on until we hear otherwise.”
PJM’s plan would change the scarcity signal for the maximum $850 penalty factor from the economic maximum of the single largest contingency to the highest actual output of a single unit. Next, it would add two lower “steps” that would trip a $300 pricing level. One step would be calculated as the highest actual output plus 190 MW — a static number derived from the synchronous reserve mean of the Mid-Atlantic Dominion zone plus one standard deviation. The second step would be calculated as the previous step plus an extension.
PJM to Review Black Start Prior to New RFP
PJM released its first request for proposals on black start units in 2013 to have them in place by 2015. As part of that process, the RTO instituted a five-year review, meaning the next black start RFP will be in 2018 for projects to be available in 2020.
To begin that process, staff will be holding a special one-hour session after the May 2 Operating Committee meeting to review results and lessons from the first RFP. Stakeholders pointed out that that is the second day of the FERC technical conference on the impact of state policies on RTO operations in PJM, ISO-NE and NYISO (AD17-11). PJM staff promised the meeting will be quick.
Earlier in the meeting, stakeholders endorsed changes to the annual revenue requirements for black start units. PJM and its Independent Market Monitor came to an agreement on having the revenue go into a non-interest-bearing account for each unit until its costs have been approved, at which point the RTO will conduct a true-up.
MISO Independent Market Monitor David Patton on Thursday repeated his call for MISO, PJM and SPP to develop better procedures for transferring control of market-to-market constraints during high congestion.
“It would save all the RTOs a lot of money and improve efficiency,” Patton said at an April 13 Market Subcommittee meeting.
Patton pointed to the Feb. 7 transfer of a Midwest constraint to PJM that provided relief for $40 million worth of congestion. (See Tornadoes, Wind Generation Drive MISO Tx Congestion.) Market Monitor staffer Michael Wander said PJM still has monitoring control of the constraint in question, and it is not unusual for an RTO to keep control of a transferred constraint for longer periods. “They review it periodically and keep it unless there’s a change in the situation,” Wander said.
“The fact that PJM physically monitors this constraint doesn’t mean that MISO is disadvantaged in any way,” Patton told stakeholders.
Northern Indiana Public Service Co.’s Bill SeDoris asked if the Monitor is notified of the transfers.
“Not only are we appraised, we’re raising concerns when the transfer hasn’t taken place. We tend to be advocates of this,” Patton said.
The Monitor reserved his harshest criticism for existing pseudo-tie procedure.
“The only reasonable requirement in our opinion is to get rid of the pseudo-tie requirement into PJM. … The fact that anyone thinks pseudo-tying is a good idea is astounding to me,” said Patton, summarizing a Section 206 complaint the Monitor filed against PJM in early April (EL17-62). (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)
Patton blasted PJM’s practice of requiring dispatch control of external generators. “This is an unprecedented requirement,” he said. All 12 MISO resources pseudo-tied into PJM were dispatched inefficiently, resulting in 114 new market-to-market constraints in 2015 and 2016, he said.
Patton encouraged stakeholders to file comments in support of his complaint.
Dynegy’s Mark Volpe asked if the spike in MISO-PJM pseudo-ties is the result of problems with MISO’s capacity market design.
“That certainly can’t be ignored,” said Patton. “But at this point, MISO’s excess capacity is a little higher than PJM’s.”
MISO: No Resettlements for Tariff Error
MISO will make a Section 205 filing seeking FERC approval for a waiver to void an eight-year-old Tariff mistake that prohibits resources incurring an excessive or deficient energy deployment charges from receiving day-ahead margin assurance payment for multiple hours.
The RTO’s Business Practices Manual only bars inefficient resources from receiving day-ahead margin assurance payment for the hour that the charge was incurred. (See MISO to Fix Recently Discovered Tariff Mistake.)
The waiver asks FERC to exclude resettlement of previous day-ahead margin assurance payments. The filing will include an affidavit from the Monitor recommending no resettlement.
“Resettlements would be extremely damaging to the market and create inefficient financial risk prospectively by undermining market confidence,” MISO said.
Bladen said there would be no technology changes to fix the mistake. “Essentially the only cost of this is administrative and legal,” he said.
Bladen also said MISO experienced a second-tier maximum generation event on April 4 in MISO South. He said MISO will review the event at the May 11 Market Subcommittee meeting. The Reliability Subcommittee will also review the event.
Expanded ELMP Price-Setting Begins May 1
MISO has filed for FERC approval to expand extended locational marginal price setting to online resources with a one-hour start-up time starting next month (ER17-1081).
The RTO will put the new eligibility into effect on May 1, Bladen said, and MISO expects to receive an order from FERC staff even without commission quorum. No one has protested the filing.
The new pricing structure preserves the requirement that offline resources must have a start time of 10 minutes or less to set prices. The move will increase the share of peaking resources eligible to set prices from 8% to 58% on a capacity basis, MISO said. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,” MISO Market Subcommittee Briefs.)
VALLEY FORGE, Pa. — After years of dragging the issue forward, Vitol’s Joe Wadsworth was about to see PJM stakeholders vote on schedule changes to accommodate spot-in sales between the RTO and NYISO.
But the scheduled vote at Wednesday’s Market Implementation Committee meeting was delayed after John Rohrbach of ACES said PJM’s simple solution for solving the problem would harm power sales in the South.
PJM had proposed delaying the spot-in request time by an hour to 10 a.m. across all seams, which would allow market participants looking to bring in power from NYISO the time to confirm they were approved by the ISO to export power. However, the delay causes issues along PJM’s southern border, Rohrbach argued.
The Market Implementation Committee delayed a vote on a schedule change to accommodate spot-in sales between PJM and NYISO because of concerns it could harm power sales in the south. | Monitoring Analytics
Rohrbach said that the daily sales market in southern states begins early in the morning and is generally done by 10 a.m., so any power that doesn’t receive approval for PJM spot-in service wouldn’t have another market to be sold in. At 9 a.m., however, opportunities still exist to make bilateral trades, he said.
“Today, if you don’t get spot-in, you have other opportunities,” he said. “By 9, it’s already starting to tail off. … If you wanted to change the time to 8 a.m., we’d actually be happier with that.”
The South is a thinly traded market and the vertically integrated utilities there are comfortable with their schedule, Rohrbach said. They are “guaranteed” not to conform with PJM’s proposed changes, he added.
The news wasn’t bad for Wadsworth, who had originally proposed a more complicated, market-based solution and later suggested that the time change be limited just to the NYISO seam, which was opposed by the Independent Market Monitor. NYISO had also proposed a market-based solution that PJM stakeholders rejected. (See “Vitol Accepts Simplified Solution to Spot-In Issues,” PJM Market Implementation Committee Briefs.)
“We are happy to compete in a competitive marketplace. … I was very clear that I didn’t want to make a change that would impact others,” Wadsworth said. “This kind of creates the balloon effect — squeeze the balloon at one place and it’s going to pop out at another.”
PJM’s Chris Pacella said the issue with the market-based proposals are that they will require software upgrades, which would take time and resources. Stakeholders acknowledged the challenges but urged Pacella to see if the proposal could be accommodated using the current system.
“I know it’s not your preference, but you should at least look at adjusting [PJM’s software] to try the NYISO solution without hurting the other seams,” Direct Energy’s Jeff Whitehead said.
“I certainly feel for the folks who are trying to solve this,” said Carl Johnson of the PJM Public Power Coalition. “We took on the problems serially. We haven’t invested our best problem solving techniques. I don’t think we’ve given this our best effort.”
Throughout the spot-in discussion, the Market Monitor has insisted on maintaining consistent rules across all seams, which Monitor Joe Bowring highlighted ironically by quoting Ralph Waldo Emerson: “‘Consistency is the hobgoblin of small minds.’” He supported considering Rohrbach’s concerns and leaving the current rules in place in the interim.
Wadsworth agreed to remove his request for a vote on the proposal, but he asked stakeholders to help him revise the problem statement. Rohrbach immediately volunteered.
Alberta-based Maxim Power announced it has closed a deal to sell its U.S. subsidiary and its five generation plants, concluding a two-year effort to stave off threats to the company’s survival.
Hull Street Energy, through its newly formed affiliate Milepost Power Holdings, paid $106 million for Maxim’s 447 MW of power generation assets in the U.S., or about $238,000/MW of generating capacity. Three of the plants are dual-fuel combined cycle plants in New England, and the others are simple cycle natural gas turbines in New Jersey and Montana.
In May 2015, Maxim reported that it had breached several financial covenants with its Canadian bank and that “significant doubt may exist with respect to the ability of the corporation to continue as a going concern.” The company said it was pursuing asset sales to improve its cash position.
The company’s outlook was not helped later in May 2015 when FERC accused it of manipulating the New England power market in a fuel-switching scheme (IN15-4). Under a consent agreement approved with FERC’s Office of Enforcement last September, Maxim agreed to pay a $4 million fine and disgorge another $4 million in earnings to ISO-NE, but it did not admit guilt. (See Maxim Power to Pay $8M to Settle Fuel-Switching Case.)
The same month, Maxim sold 176 MW of generation assets in France, its COMAX subsidiary, to an affiliate of Basalt Infrastructure for 47 million euro ($52.8 million at the time), about $300,000/MW.
Maxim said it will use $8 million (CAD) of the proceeds from the sale of its U.S. assets as collateral for letters of credit and $5 million (USD) to fulfill the settlement agreement with FERC. The company, which trades on the Toronto Stock Exchange, reported $2.2 million in net income on $94.5 million in revenue for 2016.
The assets acquired by Milepost are the 181-MW Pittsfield plant that FERC identified in the fuel-switching scheme; the 87.2-MW Forked River plant in Ocean County, N.J.; a 63.5-MW plant in Pawtucket, R.I.; the 62.1-MW CDECCA plant in Hartford, Conn.; and the 54.9-MW Basin Creek plant in Butte, Mont.
New England states will not have enough renewable resources to meet the 2025 and 2030 targets in current renewable portfolio standards without adding transmission for new onshore wind, according to a scenario analysis conducted for the New England States Committee on Electricity.
NESCOE’s Renewable and Clean Energy Mechanisms 2.0 Study used a model from London Economics to evaluate the impact of five scenarios on prices, emissions and “missing money” — the potential gap between generators’ revenues and their operating costs.
ISO-NE officials provided a briefing on the Phase I findings — part of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative — at the NEPOOL Participants Committee meeting on April 7.
The results are expected to be discussed at FERC’s technical conference May 1-2 on tensions between state public policies and wholesale markets in ISO-NE, PJM and NYISO.
One scenario that considered the accelerated retirement of the region’s nuclear capacity included sensitivities based on natural gas prices. One that looked at more renewables and transmission considered several alternatives for expanded state renewable standards.
The study concluded that new renewable generation or additional clean energy imports to New England with very low marginal costs will cut energy and capacity revenues for all other resources. Nevertheless, the study noted that under every scenario considered, nuclear generators, existing oil combustion turbines, oil internal combustion turbines, oil steam and pumped storage will remain profitable in 2025 and 2030.
The study found that under base case load conditions, New England’s addition of more than 25 million MWh annually of renewable resources and/or clean energy imports by 2025 would cause existing renewable and clean energy resources to produce less power.
If the region doesn’t build new transmission to move power from new onshore wind to load centers, both new and existing onshore wind “will operate less often and earn less revenue in 2025 and 2030,” the study said.
Unsurprisingly, it also concludes that the retirement of the region’s nuclear generation would “significantly” increase carbon emissions, as would a failure to increase renewable capacity above current RPS levels.
| New England States Committee on Electricity Renewable and Clean Energy Mechanisms 2.0 Study
Phase II of the study will test the operability of each scenario and assess additional market outcomes:
Natural gas pipeline constraints, to be discussed with the Planning Advisory Committee in the second quarter;
Forward Capacity Auction prices, also to be discussed with the PAC in Q2; and
Frequency regulation, ramping and reserves, to be discussed with the PAC in the fourth quarter.
FERC last week released the agenda for the May 1-2 technical conference (AD17-11).
Before the conference, ISO-NE plans to issue a summary of its “concept for accommodating additional state-subsidized resources and their associated pricing impacts on the capacity market.” The New England Conference of Public Utilities Commissioners Symposium in Connecticut in May and the NEPOOL Participants Committee summer meetings may allow for additional dialogue on the concept, said Chief Operating Officer Vamsi Chadalavada.
ISO-NE likely will file any related proposals with FERC by the end of 2017 to allow for implementation ahead of FCA 13.
The grid operator also is evaluating fuel security issues and their effect on the bulk power grid and plans to discuss its findings with stakeholders during the second half of 2017.
Chadalavada also updated the Participants Committee on the Updated 2017 Work Plan, saying the RTO is considering accelerating its discussions of potential pricing approaches for resource ramping.
Previously, the grid operator had delayed the resource ramping assessment to follow both IMAPP and the day-ahead reserve market enhancement assessment. The RTO now plans to hold technical sessions on how ramping currently works and to survey how other regions are handling the issue by the fourth quarter of this year.
The COO also said ISO-NE’s 2017 long-term load, energy-efficiency and solar PV forecasts are nearly complete. “The overall trend is lower net energy and seasonal peak demand for New England,” Chadalavada said.
NEPOOL Seeks Flexibility on DA Market Schedule
The NEPOOL Participants Committee unanimously supported a Tariff revision recommended by the Transmission Committee providing more flexibility in the day-ahead market schedule.
The change eliminates the requirement that real-time external transactions at interfaces not subject to coordinated transaction scheduling be submitted into the real-time energy market before “noon the day before the Operating Day.” The new text says the deadline will be specified in Section III.1.10.1A of the Tariff.
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.
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
Mulhern | RTO Insider
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.”
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.
