Page 1116 – RTO Insider

April 15, 2020

Monitor Casts Doubts on MISO-SPP CTS Benefits

By Amanda Durish Cook

SPP’s Market Monitor is cautioning that MISO and SPP must rethink some of their fees and practices before rolling out coordinated transaction scheduling (CTS) across their shared seam.

Internal Market Monitor Keith Collins says that introduction of CTS to maximize use of unscheduled transmission capacity could be ineffective unless the two RTOs remove the transmission fees and market charges they impose on each other.

MISO SPP CTS Benefits — SPP MMU Executive Director Keith Collins | © *RTO Insider*

“The benefits are difficult to quantify,” Collins said during an April 13 teleconference of the Seams Liaison Committee (SLC) of the Organization of MISO States (OMS) and the SPP Regional State Committee (RSC).

Collins said he’s collaborating with MISO Independent Market Monitor David Patton on a study to quantify possible benefits, which will likely be finished in early May. The study is part of the Monitors’ joint investigation of seams issues performed at the behest of regulators in both footprints.

“If we leave things as is, I think it’s important to understand that there may be no benefits … There need to be some additional changes in order to unlock benefits,” Collins said.

Collins additionally advised that MISO and SPP must improve the accuracy of their price forecasting to ensure that CTS delivers on its promises. The current approach to calculating forecasted prices “removes all benefits of a CTS product” because both RTOs find it difficult to anticipate price spikes or negative prices, he said.

“Assuming the current market products and market constructs, there is potentially no benefit to implementing CTS. Assuming no transaction costs and perfect knowledge of prices, CTS can likely improve total market welfare,” he said.

Collins singled out SPP for its oft-unstable prices.

“When prices can go up and down several hundred dollars in the space of five to ten minutes, it can erode some of the potential benefits of CTS if you were caught sending power at the wrong time,” he said.

SPP will soon file with FERC for approval of a ramping product designed to address its price volatility, which Collins said should help facilitate use of CTS.

MISO and PJM launched CTS across their shared border in late 2017 to allow market participants to schedule economic transmission transactions based on forecasted energy prices. PJM reported in November that CTS transactions accounted for about 19 MW per interval from June to September 2019.

M2M Efforts Proceed

Meanwhile, MISO’s IMM is wrapping up a study of the effectiveness of a MISO-SPP effort to coordinate the management of congestion on market-to-market (M2M) flowgates when one RTO is able to provide relief for a constraint.

Patton said he estimates that M2M congestion “would fall by $35 million annually if the M2M processes were administered perfectly.” The two RTOs combined rack up a little more than $184 million per year in M2M congestion due to delays or failures in testing for M2M flowgates and delays in activating them for monitoring.

To maximize flowgate management, Patton said, the RTOs should seek out, test and activate as M2M constraints the shared transmission most prone to binding. He said MISO and SPP could “accelerate” their testing and activation efforts.

The IMM will release final study results and more pointed recommendations in May.

Unsurprisingly, SPP’s Riverton-Neosho-Blackberry flowgate on the Kansas-Missouri border again weighs in as the most expensive based on preliminary numbers, costing MISO nearly $13 million in M2M settlement payments to SPP over the past two years. The flowgate has routinely been cited as the most expensive between the RTOs. (See SPP Briefs: M2M Payments from MISO to SPP Eclipse $32M.)

MISO and SPP said they are working together to estimate the congestion costs for each RTO for the top 10 most expensive flowgates in each direction. RTO staff said they would present the congestion cost estimates of the 20 flowgates at the SLC meeting in May.

April 15, 2020

Align Tool Set for 2021 Rollout

By Holden Mann

NERC’s Align software project is now set to be released in the first quarter of 2021, after the rollout date for the tool was revised last year from September 2019 to the second or third quarter of this year. (See Align Rollout Delayed to 2020.)

Align — formerly known as the CMEP (Compliance Monitoring and Enforcement Program) Technology Project — is intended to improve and standardize compliance monitoring and reporting processes across the ERO Enterprise.

NERC Align Tool — NERC CEO Jim Robb | © *ERO Insider*

Speaking to the Member Representatives Committee’s (MRC) premeeting informational conference call on Wednesday, NERC CEO Jim Robb attributed the further delay to development of the Secure Evidence Locker. This security feature was originally intended to be included in an update but was added to the initial release at the request of registered entities when the project was delayed for the first time last summer, because of concerns over the software provider’s ties to a Hong Kong-based private equity firm. (See NERC Investigating Chinese Tie to Software Vendor.) [NOTE: An earlier version of this article incorrectly said the feature was added at the request of regional entities.]

The ongoing development delay has caused the cost of the project to rise beyond its original estimate by up to $2 million, according to Andy Sharp, NERC’s interim CFO. Approval for the expenditure will be requested during the MRC conference call scheduled for May 14, with the funding expected to come from NERC’s operating contingency reserves for 2021.

Upfront costs for the project of $3.8 million, which were not included in NERC’s budget for this year, will also require a variance to be filed with FERC, Sharp said. The organization expects to fund the investment with a projected $1 million surplus from the operating contingency reserves for this year, in addition to debt financing of $2.8 million.

Sharp told attendees that he is pursuing a 60-month term for this loan rather than the typical 36 months, as the current low interest rates mean overall servicing costs will be the same or lower than previous projections of debt service for this year.

“The costs of delay and implementation of these sorts of projects are significant, and they will increase if there is further delay,” NERC Board of Trustees Chair Roy Thilly said. “So what we need to do is move carefully, effectively and expeditiously at the same time to resolve these matters.”

Robb Delivers COVID-19 Update

Robb also provided listeners with an update on NERC’s response to the COVID-19 pandemic. The organization has now confirmed three cases of the coronavirus among its staff, including the first case reported in March. (See NERC Employee Tests Positive for Coronavirus.) However, all have either fully recovered or are recovering well, and Robb said there is “no evidence of any community spread through the NERC ecosystem.”

The ERO is presently in a “full remote work posture,” which it plans to maintain through July 4, though its offices are expected to formally reopen by May 25. In addition, all external meetings through June have been either canceled or converted to conference calls. Events previously scheduled for July and August are expected to undergo similar changes.

GridSecCon, the annual security conference sponsored by the Electricity Information Sharing and Analysis Center scheduled for Oct. 20-23, has also been canceled this year, while the inaugural Electric Power Human Performance Improvement Symposium, planned for Sept. 29 to Oct. 1, has been delayed to next spring.

NERC said earlier this month that the industry has “[taken] aggressive steps” in response to the pandemic, with most utilities either having a written response plan or currently developing one, and a majority pledging to support mutual aid requests from others involved in a pandemic emergency. (See Industry Pandemic Prep Encouraging, NERC Says.) The organization issued a Level 2 alert in March and has activated its Business Continuity Plan.

April 15, 2020

MISO Begins Bid to Merge Tx, Queue Planning

By Amanda Durish Cook

MISO staff will commence work on a project to better align generation interconnections and transmission planning after stakeholders retired the task team charged with suggesting ways to bridge the two processes.

Stakeholders created the Coordinated Planning Process Task Team in November to probe how MISO could increase coordination between the separate studies underpinning the RTO’s Transmission Expansion Plan (MTEP) and its generator interconnection queue process.

The team in February forwarded MISO’s Planning Advisory Committee and Planning Subcommittee a list of topics to address. (See MISO Committees Tackle Queue, Tx Planning Disparities.) With the task list in hand, the PAC on Wednesday voted to retire the team during a teleconference.

MISO will now examine the two study processes as a first step in possibly unifying them. Senior Manager of Expansion Planning Edin Habibovic said the RTO would begin with “an in-depth review of MISO planning study objectives, methodologies and assumptions.”

“MISO believes it is prudent to review MISO’s planning processes, identify correlation and document rationale for any disparities between them,” Habibovic said during a Planning Subcommittee teleconference Tuesday.

Habibovic said the review will occur in planning meetings and special meetings scheduled through August.

MISO renewable proponents and some state regulators have repeatedly contended that the RTO unfairly relies on interconnection customers to finance increasingly expensive new transmission capacity under the pretext of network upgrades and may be neglecting its responsibility to get major projects approved in its transmission packages. Renewable advocates have questioned why interconnection studies show the need for expensive transmission upgrades when studies performed under the MTEP do not.

Stakeholders have suggested MISO better align the timelines of interconnection and MTEP planning and ensure the studies draw on similar data, including dispatch assumptions. The synchronization effort could have the RTO approving more transmission projects by MTEP 2021. (See MISO Seeks Ideas for Streamlined Tx Planning.)

MISO is currently juggling 10 separate queue cycles among its four planning regions, with five additional cycles set to begin over the next year. Senior Manager of Economic Planning Neil Shah said the unusually high number of queue cycles being processed in unison will be an obstacle to aligning timelines with MTEP.

April 15, 2020

MISO to File 1st COVID-19 Queue Waiver Request

MISO will ask FERC to waive a specific generation interconnection queue requirement to assist developers whose projects face construction preparation delays in the face of the COVID-19 pandemic.

The RTO will request a “limited FERC waiver” of its June 25 deadline for developers to demonstrate site control for projects entering MISO South’s 2020 interconnection cycle, Manager of Probabilistic Resource Studies Ryan Westphal told listeners on a Planning Advisory Committee call Wednesday. MISO has settled on a 60-day extension of the deadline.

MISO COVID-19 Queue Waiver — Ryan Westphal, MISO | © *RTO Insider*

Westphal said the chief concern of most interconnection customers is how they will meet deadlines to show exclusive land use for generation projects during the pandemic. MISO’s next site control deadline doesn’t occur until September, when the 2020 MISO West batch of projects enter the queue.

“There’s still uncertainty of when some states and localities will lift restrictions,” he said. “We’re looking at the near future and can go back to FERC to extend waivers as necessary.”

Westphal said the request specifically applies to the site control deadline and would not affect other queue deadlines. However, he said, additional waivers “are on the table” if the pandemic wears on and groups of interconnection customers encounter similar obstacles. (See MISO Considers COVID-19 Queue Waivers.) “At least” two interconnection customers have reached out to MISO to discuss special circumstances affecting their projects, he said.

MISO will not hold a call to discuss the finalized filing with stakeholders and will file in the “next two weeks,” Westphal said.

Social distancing efforts have been skewing MISO load and planned outages since mid-March. (See COVID-19 Transforming MISO Load, Outage Schedules.)

— Amanda Durish Cook

April 14, 2020

Va. 1st Southern State with 100% Clean Energy Target

By Rich Heidorn Jr.

Virginia Gov. Ralph Northam (D) on Sunday signed into law landmark legislation committing the state to closing most of its coal-fired generation by 2024 and making it the first Southern state to adopt a 100% clean energy standard.

Virginia clean energy — Gov. Ralph Northam | *NGA*

“These new clean energy laws propel Virginia to leadership among the states in fighting climate change,” Northam said in a statement. “They advance environmental justice and help create clean energy jobs. In Virginia, we are proving that a clean environment and a strong economy go hand-in-hand.”

The Virginia Clean Economy Act (House Bill 1526 and Senate Bill 851) creates a CO2 cap-and-trade program to reduce emissions from power plants and amends the Clean Energy and Community Flood Preparedness Act, which committed the state to joining the Regional Greenhouse Gas Initiative (RGGI).

The legislation is a stunning turnaround for Virginia’s energy policy, spurred by Democrats’ takeover of the House of Delegates and the Senate in November. Last year’s budget approved by Republicans, Northam noted, prohibited Virginia from joining RGGI.

The new law:

Replaces the existing voluntary renewable portfolio standard program with a mandatory RPS that applies to electric utilities and licensed competitive suppliers. It requires Dominion Energy Virginia to be 100% carbon-free by 2045 and Appalachian Power by 2050.
Sets an energy efficiency resource standard and requires a third-party review of whether energy companies meet savings goals.
Establishes 5,200 MW of offshore wind as “in the public interest,” up from 16 MW. It requires Dominion to prioritize hiring local workers from historically disadvantaged communities for the offshore project and to work with the state on apprenticeship and job training programs. Dominion must include an environmental and fisheries mitigation plan in its construction.
Establishes that 16,100 MW of solar and onshore wind is “in the public interest” and expands net metering for rooftop solar. It sets an energy storage target of 2,400 MW by Dec. 31, 2035.
Removes a provision declaring that planning and development activities for new nuclear generation facilities are in the public interest.

“By joining RGGI, Virginia will take part in a proven, market-based program for reducing carbon pollution in a manner that protects consumers,” Northam said. The Department of Environmental Quality will create and run an auction program to sell allowances into a market-based trading program.

Revenues from the sale of allowances will be distributed by the Department of Mines, Minerals and Energy to low-income, disability, veteran and age-qualifying energy efficiency programs; additional energy efficiency measures for public facilities; coastal resilience efforts; and administrative costs.

The State Corporation Commission will be prevented from issuing a certificate for public convenience and necessity for any investor-owned utility to own, operate or construct a generator that emits carbon until the General Assembly receives the state Air Pollution Control Board’s report on how to achieve 100% carbon-free electricity generation by 2050 and whether the legislature should ban new generation units that emit carbon. The report is due Jan. 1, 2021.

Utility applications to construct a new generating facility will include the social cost of carbon, as determined by the commission, as a cost adder.

April 14, 2020January 29, 2024

Tri-State G&T, Delta-Montrose Reach Withdrawal Deal

Tri-State Generation and Transmission Association said Monday it has entered into a withdrawal agreement with Delta-Montrose Electric Association (DMEA), sticking to the terms of a 2019 settlement.

Westminster, Colo.-based Tri-State said DMEA will pay $88.5 million, including $26 million to purchase facilities, and forfeit another $48 million in patronage capital to leave the cooperative, effective June 30. The agreement is subject to certain conditions and approvals, including FERC’s.

DMEA is a rural electric distribution cooperative that serves about 28,000 member-owners in western Colorado. The co-op sought to sever ties with Tri-State after determining it could obtain cheaper and environmentally cleaner energy supplies from other sources.

Tri-State and DMEA last year agreed to part ways in a settlement agreement that allows for DMEA’s purchase of certain assets and facilities, the termination of certain existing contracts between the two entities, and assignment by Tri-State of its wholesale electric service contract to a third-party provider.

Tri-State and DMEA will also enter into new contracts for the continued operation of transmission and telecommunications systems.

“The withdrawal agreement aligns with our settlement,” Tri-State CEO Duane Highley said.

DMEA’s forfeiture of the current balance of its patronage capital is not included in the payment. All Tri-State members have a patronage capital account, which represents each member’s ownership in the co-op.

Tri-State, a member of SPP’s Western Interconnection Energy Imbalance Service set to go live in February, has 46 members, including DMEA.

Kit Carson Electric Cooperative left Tri-State in 2016. Two other Tri-State cooperatives, United Power and La Plata Electric Association, are seeking termination-fee information through proceedings at the Colorado Public Utilities Commission.

The Tri-State board of directors on Friday approved a formula for standardizing the fee charged to members if they break their power-supply contract and leave the organization.

April 14, 2020

California Travels down Electrification Road

By Hudson Sangree

The California Energy Commission boosted the state’s efforts to electrify buildings and improve the efficiency of electric appliances last week when it approved electrification and green energy ordinances in seven cities and required that swimming pool pump motors — a significant energy user in homes and hotels — become more efficient.

California has nearly 1.2 million swimming pools, more than one-fifth of all pools in the U.S., according to real estate data tracking firm Metrostudy. Replacing older burnt-out motors with high-efficiency ones eventually will save 451 GWh/year, the commission estimated.

“To put that amount of savings into perspective, that’s enough electricity to power the entire fleet of trains operated by BART, the Bay Area Rapid Transit train system — serving San Francisco, Oakland and many of the cities on the way to San Jose — for a year,” Noah Horowitz, the director of the Natural Resources Defense Council’s Center for Energy Efficiency Standards, wrote in a blog post praising the move.

The new California rules bolster national energy efficiency standards for pool pumps that take effect in 2021, the NRDC said.

California Electrification — Pacifica is one of seven cities that adopted building electrification or green-energy plans approved by the California Energy Commission. | *U.S. Army Corps of Engineers*

In its April 8 meeting, the CEC also approved municipal rules for building electrification and energy efficiency in new construction that exceed current state standards.

The communities include Cupertino, the Silicon Valley suburb where Apple has its headquarters. The city of 60,000 residents adopted an ordinance requiring that new buildings be all-electric. The nearby cities of Saratoga and Pacifica will require new single-family and many multifamily buildings to use electricity for heating and cooling systems and water heaters.

San Francisco, along with San Rafael and Mill Valley in Marin County, passed rules requiring new buildings and remodels to achieve high scores under green building certification programs, including Leadership in Energy and Environmental Design. Those requirements are expected to result in the installation of electric heating and cooling systems in place of those that use natural gas.

A Los Angeles ordinance approved by the CEC requires that all buildings install cool roofs for the “reduction of the heat-island effect.”

Achieving Zero Carbon

The cities join a growing number of local governments instituting aggressive changes to reduce fossil-fuel emissions for residential and commercial structures. Last year, Berkeley became the first city to ban natural gas in new construction as other cities weighed similar measures. (See West Coast Pushes for Building Electrification.)

The Public Utilities Commission recently devoted $200 million to jump-start electrification efforts, for “the purpose of decarbonizing California’s residential buildings in order to achieve California’s zero-emissions goals,” Commissioner Liane Randolph wrote in her proposed decision, which the commission adopted March 26.

The state’s twin goals of greatly reducing greenhouse gas emissions and relying wholly on renewable and nonpolluting energy by midcentury are driving the electrification effort. Advocates see vehicles and buildings as areas where fossil fuels can be eliminated.

The cities that have adopted green building and electrification efforts are primarily located in wealthier and politically liberal coastal California. Residents of the state’s more conservative interior have, in some cases, resisted such efforts. (See Bakersfield Balks at Electrification with CPUC.)

But the movement is expected to grow in coming years both through mandatory efforts and voluntary replacement of natural gas furnaces and water heaters with energy-efficient systems.

The Sacramento Municipal Utility District, for example, offers rebates of $1,500 to $4,000 to residents who upgrade to electric heat pumps for home heating and cooling and $2,500 rebates for those who install heat-pump water heaters. SMUD has also been encouraging the construction of all-electric homes.

“Customers with all-electric homes in SMUD’s service area are well positioned for a renewable energy economy and can typically save $400 compared to homes that rely on gas for space heating and hot water,” the utility said in a news release. “These homes will help community-owned SMUD meet its aggressive commitment to reach carbon neutrality by 2040 and surpass the state’s greenhouse gas reduction goals of 80% by 2050.”

April 14, 2020

Methane Levels Hit All-time High

By Rich Heidorn Jr.

Emissions of heat-trapping methane hit a new high in 2019, according to preliminary data from the National Oceanic and Atmospheric Administration.

The agency reported globally averaged atmospheric methane levels hit 1,874.7 parts per billion in December 2019, an increase of almost 0.5% from a year earlier and the second-largest annual increase in the last 20 years. NOAA cautioned that its analysis was preliminary; final numbers are expected in November.

Methane is emitted by cows, sheep, microbes in wetlands, and oil and gas wells. While it remains in the atmosphere for only about a decade, much less than CO2, it absorbs much more energy than CO2. Thus, EPA says methane’s g lobal w arming p otential (GWP) is about 30 times that of carbon dioxide.

After almost leveling off between 2000 and 2005, methane emissions have increased sharply since 2006, a period in which U.S. natural gas production has increased by more than 70%, according to the Energy Information Administration.

Methane emissions from the oil and gas sector totaled almost 80 million tons in 2017, 6% of global energy sector greenhouse gas emissions, according to the International Energy Agency.

Because methane is valuable, IEA says almost half of the emissions from drilling could be captured at no net cost.

“Emissions remain high despite initial industry-led initiatives and government policies announced recently,” IEA said. “Implementing abatement options quickly and at scale remains a real challenge.”

ExxonMobil Field Trials

ExxonMobil announced last week it is conducting field trials of eight methane detection technologies, including satellite and aerial surveillance monitoring, at nearly 1,000 sites in Texas and New Mexico.

“The field tests are evaluating effectiveness and scalability of a range of next-generation detection technologies that, in addition to satellites, use drones, planes, helicopters, [and] ground-based mobile and fixed-position sensors. All technologies and deployment methods will be used to detect leaks and identify potential solutions that can be shared with other oil and gas operators,” the company said.

“We are already seeing the benefits of some of these technologies,” said Staale Gjervik, president of ExxonMobil subsidiary XTO Energy. “Through the trials, we have discovered methane sources that would otherwise not have been detected as efficiently or quickly under the current methods prescribed by regulations. The company is committed to immediately investigating and fixing methane emissions that are detected during the trial.”

The company said it reduced emissions by almost 20% in its U.S. unconventional operations between 2016 and 2019. It has made a corporate-wide commitment to reduce methane emissions by 15% and reduce flaring by 25% by the end of 2020.

In March, ExxonMobil proposed a regulatory model for reducing emissions.

The Trump administration in 2018 reversed proposed regulations to reduce leaking, venting and flaring of methane at drill sites on federal and tribal land and a requirement that companies monitor and repair methane leaks.

Dry natural gas production grew by 10% to a record 92.2 Bcfd in 2019 but is expected to drop slightly in 2020 and 2021 because of low prices, EIA said last week in in its Short-Term Energy Outlook. The agency also said its forecasts are “subject to heightened levels of uncertainty” because the impacts of the COVID-19 pandemic on energy markets are “still evolving.” (See related story, EIA: Renewable Capacity to Grow in 2020.)

The economic shutdown caused by the pandemic could reduce global carbon dioxide emissions by more than 5% this year, according to the Global Carbon Project. It would be biggest reduction since the end of World War II.

April 14, 2020

New Pa. Generator Hedging Gas Prices with Ethane

By Michael Yoder

The Marcellus Shale formation has turned Pennsylvania into the nation’s No. 2 natural gas producer and made it a favorite spot for new gas-fired electric generation. Natural gas’s share of the state’s electric production more than doubled to 36% from 2010 to 2018.

But there is something different about the state’s newest generating plant. If natural gas prices rise from their current low prices, Competitive Power Ventures’ 1,050-MW Fairview Energy Center near Johnstown can add up to 25% ethane into its fuel mix — the first generation facility of its size in the world with that kind of flexibility, according to CPV.

CPV’s Fairview Energy Center | *Competitive Power Ventures*

Located on an 86-acre former brownfield site in Jackson Township, Cambria County, the General Electric-designed combined cycle plant successfully completed ethane testing in March and went into full combined operation this month.

Bill Lawson, senior engineer for new products at GE Gas Power, said customers have been seeking the ability to burn an array of gases to respond to fluctuating commodity prices. Lawson said GE began looking several years ago at shale gas and its byproducts, including ethane, that could serve in power generation.

“GE saw this trend developing early and focused technology development to broaden our fuel flexibility,” Lawson said.

Price Trends

Ethane, commonly referred to as a natural gas liquid, is a hydrocarbon that can be found underground in shale and coal beds. In addition to being burned as a fuel, ethane also is used to produce ethylene, a chemical used in the manufacturing of plastics, automotive antifreeze and detergent.

According to the Energy Information Administration, ethane prices tracked crude oil spot prices until 2008 but began to diverge as U.S. production growth from shale gas and tight oil formations overwhelmed ethane consumption by the domestic petrochemical industry. By 2012, ethane prices closely tracked natural gas prices, staying within $1/MMBtu of the Henry Hub natural gas spot price on a heating-value-equivalent basis.

Since late 2017, EIA says, ethane demand has been growing because of increased petrochemical use and ethane export capacity. “As a result, ethane prices began to move away from their link to natural gas prices, and they are now bracketed by propane at the top and natural gas at the bottom of the range,” EIA said.

Ethane spot prices fell 17% from January to March this year — while natural gas prices dropped 11% and international crude oil fell about 46% — because of the economic slowdown from the COVID-19 pandemic.

Nearby Pipelines, Transmission

Natural gas for Fairview comes from the Enbridge Texas Eastern Transmission gas lines, about 1 mile north of the plant site. The ethane comes from Mariner East pipelines located on site. The plant also is adjacent to a 500-kV circuit that delivers its output to PJM, enough for 1 million homes and businesses.

CPV, which has ownership interests in 4.2 GW of generation in the U.S, partnered with Osaka Gas on the plant.

Jeff Ahrens, vice president of engineering and construction for CPV and the director of the $1 billion project, said the company wanted to incorporate ethane from an early stage in the plant’s development. While CPV had experience with the equipment and engineering needed for natural gas generators, adding ethane presented new challenges.

“It’s the first of its kind on this scale, so it required a lot of patience to make sure we did it right, make sure everything was designed correctly and look at all the different scenarios that the system needed to have to be reliable and safe for us,” Ahrens said. “Every step was somewhat new.”

Fairview was Ahrens’ second project for CPV, following the St. Charles Energy Center, a 745-MW combined cycle plant in Waldorf, Md., that went into operation in 2017.

Ahrens said one of the biggest challenges was that ethane comes to the plant in liquid form and requires vaporization to mix with the natural gas.

Natural gas is more buoyant than ethane, Ahrens said, so designs had to be created to find the right way to mix the two. The result was a GE vaporizer as large as a truck to mix the two fuels.

Fairview took nearly three years of development before construction began, requiring a team of hundreds of GE and CPV engineers, manufacturers, logistics exports and transportation workers.

“It required a lot of research, understanding [and] getting the right team members together who either had some experience or knew people who had experience, like petrochemical guys in the oil and gas industries,” Ahrens said.

April 14, 2020

ERCOT Sees Little Effect on Demand from COVID-19

By Tom Kleckner

While the COVID-19 pandemic has dampened industrial output and electricity load in much of the nation, ERCOT continues to set the pace for increases in demand.

The Texas grid operator, which has enjoyed fairly consistent 2% load growth in recent years, registered a new demand record for April when the system peaked at 55,180 MW on Wednesday during the hour ending at 5 p.m. CT. The preliminary operational data broke the previous mark of 53,846 MW, set in April 2017.

An ERCOT spokesperson attributed the record to the state’s higher-than-normal temperatures that pushed up demand during the day.

According to the National Weather Service, temperatures in the Dallas/Fort Worth Metroplex hit 97 degrees Fahrenheit on April 8, setting a daily record high. The low temperature of 71 F set a record for the highest minimum temperature for the date.

The monthly record was the first of 2020 after ERCOT set nine during the past two years. March’s peak demand of 52,819 MW was down 13.1% from last year’s March high of 60,756 MW.

The peak came as the nation’s electricity demand plunged to a 16-year low during the first week of the month. The Edison Electric Institute and energy traders cited closed offices, reduced industrial activity and mild weather for slowing demand.

The U.S. Energy Information Administration expects total U.S. power consumption to decline by 3% in 2020. (See related story, EIA: Renewable Capacity to Grow in 2020.)

ERCOT began monitoring the pandemic’s effect on load patterns in early March. Last week, the grid operator began providing weekly updates on the patterns on its Trending Topics webpage (under Presentations & Other).

It said there has been little effect on its daily peaks but that morning loads are 6 to 10% lower than what the forecast model would typically predict. (See “Texas Grid’s Weekly Energy Usage Down 2% in March,” ERCOT Technical Advisory Committee Briefs: April 1, 2020.)

“The overall load reduction for the ERCOT region has leveled off over the past two weeks,” said Calvin Opheim, ERCOT manager of load forecasting and analysis. He said energy usage was down about 2% for the weeks of March 22 and 29.

ERCOT staff are using a backcast model in their analysis, comparing model results using actual weather versus actual hourly load. The difference between what actually occurs and what the model shows is referred to as a “model error.” The model was last updated in January and does not reflect the pandemic’s effect, making it a “pure model” for analyzing the difference between the model and actual outcomes. The pandemic is a component of the model error.

Before the pandemic, ERCOT had projected a record summer peak demand of more than 76,600 MW, a 3,500-MW increase over last year. It will release a final forecast in May. (See ERCOT Sees Summer Repeat: Record Peak, Tight Reserves.)