Page 1275 – RTO Insider

September 5, 2017

No Agreement on Tipping Point for LNG Exports

By Michael Brooks and Rich Heidorn Jr.

There is wide agreement among economists that exporting too much U.S. natural gas could expose U.S. consumers, industrial users and electric generators to much higher world prices. But there is no agreement on what is the tipping point, and how soon could the U.S. get there. The answer depends on at least three variables: How big is the U.S. supply? How much demand is there for U.S. exports? And what will be the impact of increasing exports on U.S. gas prices?

Below, RTO Insider summarizes the current data and the projections on these variables.

Supply Debate

According to the U.S. Energy Information Administration, there was about 2,355 trillion cubic feet (Tcf) of technically recoverable gas in the U.S. as of Jan. 1, 2015. “Technically recoverable” gas includes proved (gas expected to be produced under current economic conditions) and unproved reserves (gas that is recoverable based on current technology, without regards to economics).

The reference case of its 2017 Annual Energy Outlook (AEO) projects gas production to grow at almost 4% annually through 2020, about equal to the growth since 2005. After 2020, EIA projects a 1% annual production growth rate as net export growth moderates and domestic consumers more efficiently use their gas.

In July, the Potential Gas Committee — a group of scientists from industry, academia and government — said that recoverable gas is about 20% higher than EIA’s estimate. The committee’s biennial report put the figure at 2,817 Tcf as of Dec. 31, 2016.

The PGC’s new estimate represents a 12% increase over its previous report, the fifth consecutive increased projection. The group attributed the increase largely to a re-evaluation of production and development of shale gas plays across the country, with the Appalachian Basin plays — which include the Marcellus and Utica — especially having much more than previously thought.

Alexei Milkov, professor of geology and director of the Potential Gas Agency at the Colorado School of Mines, presented the report in July at American Gas Association headquarters in D.C. He said the lopsided increase in the Appalachian plays is because it is more economic for gas producers to explore existing sites, rather than drill new wells. Producers also are drilling longer laterals when fracking and increasing their use of “slick water” — water with added chemicals that reduces friction, allowing for more efficient gas production.

Consumption

Last month, EIA reported that the U.S. has enough natural gas to last about 86 years, or about 2101, based on the 2015 consumption rate of about 27.3 Tcf per year.

“The actual number of years will depend on the amount of natural gas consumed each year, natural gas imports and exports, and additions to natural gas reserves,” the agency said.

EIA actually projects consumption rising to almost 40 Tcf by 2050, an average annual increase of almost 1.2%. The 2017 AEO reference case projects a total consumption of 1,227.2 Tcf from 2016 to 2050. This figure includes a maximum of 4.4 Tcf annually (about 12 Bcfd) in net LNG exports.

Assuming consumption increases continue at about 1.2%/year after 2050, the U.S. would actually run out of gas in 2075, based on EIA’s supply estimate.

Using the PGC’s total reserve estimate and the same consumption increase extends supply to 2083.

The Industrial Energy Consumers of America (IECA) has been sounding alarms about growing exports, noting in June that EIA’s projections show the U.S. will exhaust 56% of its supply by 2050. (See related story, Industrial Consumers Concerned by Efforts to Expand LNG Exports.)

The group’s estimate subtracted from EIA’s 2016 reserve estimate the supply from Alaska, a reduction of almost 7%. It did this because those Alaskan “resources are not available to consumers in the lower 48 states,” it said. This would put the lower 48 on track to run completely out by 2072.

IECA says the Energy Department has approved exports of 20.6 Bcfd to non-FTA countries, almost equal to U.S. industrial gas consumption and almost three-quarters of the amount burned for power generation. “The U.S. should never agree to ship LNG to countries that subsidize their manufacturers and power plants,” the group said.

Exports Growing

U.S. natural gas exports jumped 30% to 6.35 Bcfd in 2016, a record high, according to EIA. Almost 92% of exports were via pipelines to Mexico (up 29% from 2015) and Canada (up 10%). Exports to Mexico, which have more than doubled since 2013, are expected to continue growing with the completion of pipeline projects currently under construction and as demand from new natural gas-fired generators in Mexico increases.

Mexico, Canada and four other countries with free-trade agreements with the U.S. — Chile, South Korea, Jordan and the Dominican Republic — accounted for 44% of LNG exports in 2016, according to IECA. The remaining 56% was consumed by 13 non-FTA countries, led by India, China, Argentina and Japan.

Exports to Canada have been increasing steadily since 2000, when the 1.3-Bcfd Vector pipeline began shipping gas from Chicago. The trend has accelerated since 2011 as several pipelines that had been importing gas from Canada were reversed in the Midwest and Northeast.

As of March 2017, U.S. natural gas exports to Canada were 3.21 Bcfd and those to Mexico averaged 4.04 Bcfd.

Although the U.S. remained a net importer of natural gas in 2016 — buying 685.3 Bcf more than it sold — net imports dropped 27% from 2015 and 50% from the previous five-year average (2011-15).

In its AEO reference case, EIA projects LNG exports to exceed pipeline exports by the early 2020s, rising steadily before leveling at 4.4 Tcf in 2035.

The two U.S. export terminals in operation — Cheniere Energy’s Sabine Pass LNG Terminal in Louisiana and ConocoPhillips’ Kenai LNG Plant in Alaska — have a combined capacity of 2.3 Bcfd.

Loading of the first commissioning cargo at Sabine Pass LNG Terminal in February 2016 | *Cheniere Energy*

According to FERC, 11 other terminals with a combined capacity of 16.4 Bcfd have been approved, all but four of which have commenced construction. An additional 14 terminals with total capacity of 25 Bcfd have pending applications or are in the prefiling stage, the commission says.

“After 2020, U.S. exports of LNG grow at a more modest rate as U.S.-sourced LNG becomes less competitive in global energy markets,” EIA predicts. Currently, most LNG is traded under oil price-linked contracts, but this is expected to change as the global LNG market expands, EIA said.

However, the reference case also included fuel switching to gas because of EPA’s Clean Power Plan, which has been stayed by the Supreme Court and which Administrator Scott Pruitt is trying to rewrite. Natural gas consumption in the electric power sector is about 6% higher in the reference case in 2040 than the “No CPP” case.

Consumption: How Much Demand Is There?

Some analysts say the rush to build export facilities threatens to create a glut.

“Just as the U.S. terminals are ramping up capacity, the global LNG market is entering a period of oversupply and weak spot LNG prices across the major gas importing regions,” Columbia University’s Center on Global Energy Policy said in a November 2016 report. “In this new market environment, it seems increasingly uncertain whether America’s new flexible LNG export capacity will be fully utilized toward the end of the decade.”

For exports to be economic, the report notes, the delivered cost of LNG must be lower than the target market’s spot price. This “arbitrage window” is still open, but narrow, in the European and Asian markets — “quite remarkable, given how much spot natural gas prices have fallen in both regions over the last two years,” the report said. The two benchmark spot prices for the European (U.K.) and Asian (Japan/South Korea) markets had fallen to $4.69/MMBtu (down 40%) and $6.08/MMBtu (down 60%), respectively, as of Sept. 30, 2016, it said.

“By adding a vast supply of flexible uncommitted LNG into the global natural gas market, U.S. LNG is already changing gas market dynamics around the world in profound ways,” the report concludes. “Whether the world will want to buy all that gas, however, will depend on even small changes in a number of key variables, with significant consequences for future investment, technological and commercial innovation, and global gas trade.”

Price Impact

The economics for exporting LNG, like those for converting to gas-fired power generation, are the product of the U.S. shale gas revolution that has dramatically reduced prices and increased supply.

But EIA predicts a steady increase in prices under all its future scenarios:

In its reference case, EIA forecasts Henry Hub prices nearly doubling from $2.50/MMBtu to $4.90/MMBtu between 2016 and 2020. Average delivered prices rise a more modest 48% over the same period.
Under EIA’s high oil price scenario, Henry Hub prices increase 75% by 2020, with average delivered prices rising 37%. The scenario assumes a barrel of Brent crude oil — currently priced at about $50/barrel — reaches $226 by 2040, compared to $109 in the reference case and $43 in the low oil price case.
The high oil and gas resource and technology case — which models lower gas costs and higher supplies than in the reference case — predicts a 60% increase in Henry Hub prices and 31% in average prices by 2020. The lower prices increase domestic consumption and exports.
In comparison, in the low oil and gas resource and technology case, “prices near historical highs drive down domestic consumption and exports.” Henry Hub prices rise by 131% by 2020, while average delivered prices rise by about two-thirds.

Henry Hub, long the benchmark for U.S. gas contracts, is increasingly helping to set international prices. In the first six months of 2017, the volume of Henry Hub futures traded outside of typical U.S. trading hours jumped 31% compared with the same period last year, according to the New York Mercantile Exchange.

Kenneth Medlock, senior director of Rice University’s Center for Energy Studies, says added LNG exports will not have a substantial impact for almost a decade because the large amount of LNG supply coming online globally will prevent the U.S. from exporting more than 12 Bcfd before 2025.

Medlock coauthored with Oxford Economics an October 2015 study for the Energy Department on the macroeconomic impact of increased LNG exports. It concluded LNG exports raised domestic prices somewhat and lowered prices globally, with Asia most sensitive to price movements.

It projected that if LNG exports met a global demand of 20 Bcfd, it would only increase U.S. GDP by 0.03 to 0.07%, or $7 billion to $20 billion at today’s prices.

Australia’s Lesson

Australia’s surge in LNG exports provides a cautionary tale for the U.S. The country, which exported 62% of its production last year, was hit with a February heat wave that resulted in domestic shortages, spiking prices to as high as $17/MMBtu and leading to blackouts. It was responsible for 17% of LNG exports in 2016, second only to Qatar (30%).

Such a crisis is unlikely soon in the U.S.: The country would need to ship about 45 Bcfd — seven times its current rate at current production levels — to match Australia’s exports as a share of total production.

September 4, 2017

Industrial Consumers Concerned by Efforts to Expand LNG Exports

By Michael Brooks and Rich Heidorn Jr.

The U.S. is becoming a net exporter of natural gas for the first time since 1958, a boon to the nation’s balance of trade and a bragging point for the Trump administration but a source of concern for industrial gas customers for whom cheap gas has sparked a resurgence in U.S. chemical production.

The historic shift is the result of both increased pipeline shipments to Canada and Mexico and the expansion of LNG export capacity.

The opening in February 2016 of Cheniere Energy’s Sabine Pass LNG export terminal in Louisiana — the first export facility in the lower 48 states — helped push the country from being a net importer of natural gas to a net exporter for four of the first six months of 2017, according to the U.S. Census Bureau.

The U.S. ranked 16th in LNG exports in 2016, with only a 1.1% market share. But about half of global export capacity under construction is in the U.S.

Sabine Pass and the only other existing export terminal in the U.S., ConocoPhillips’ Kenai LNG Plant in Nikiski, Alaska, have a combined capacity of 2.3 Bcfd. An additional 11 other terminals with a combined capacity of 16.4 Bcfd have been approved, and 14 terminals (25 Bcfd) have pending applications or are in the prefiling stage, according to FERC.

The Trump administration has pushed to expand LNG exports, particularly to European Union countries dependent on Russian gas, continuing an Obama-era policy to counter Russian influence. Russia supplied more than one-third of Europe’s gas in 2016 and is expected to remain its biggest supplier through 2035.

Although some government strategists find U.S. shale gas wealth appealing as a geopolitical lever, economists say exporting too much gas could expose U.S. consumers, industrial users and electric generators to much higher world prices. Australia’s surge in LNG exports provides a cautionary tale. The country, which exported 62% of its production last year, was hit with a February heat wave that resulted in gas shortages and blackouts.

But there is no agreement on what is the tipping point for the U.S. or how soon we could get there. The answer depends on at least three variables: How big is the U.S. supply? How much demand is there for U.S. exports? And what will be the impact of increasing exports on U.S. gas prices? (See related story, No Agreement on Tipping Point for LNG Exports.)

Chris McGill, vice president of policy analysis for the American Gas Association, which represents more than 200 gas utilities, is unconcerned.

“We have not believed that incremental elements of demand — like LNG growing over time, like more gas for power generation — destroy the market for small volume users,” he said. “In fact, if you look at the recent history, and particularly since the shale revolution, we have a market that’s been demand-constrained, not supply-constrained.”

John Shelk, CEO of the Electric Power Supply Association, said independent power producers aren’t concerned by an increase in exports influencing electricity prices either. “We agree with our producer colleagues that the supply curve is so flat that any increased demand from LNG exports going up can be met without a meaningful uptick in prices,” he said.

But the Industrial Energy Consumers of America (IECA) is alarmed by the trend. The group, which represents companies with 2,600 facilities and 1.7 million employees, issued a statement in July disputing Trump’s boast that the U.S. is “sitting on massive” energy reserves. It called for a moratorium on further approvals of LNG exports to countries without free-trade agreements (FTAs) with the U.S.

Citing EIA data, IECA President Paul N. Cicio claimed “56% of all natural gas resources will be consumed” by 2050. The claim that the U.S. has a 100-year supply of gas, he says, “is a myth.”

Regulation of Exports, Terminals

The Natural Gas Act of 1938 stipulates that the U.S. Department of Energy must approve any requests to import or export gas based on whether it is in the “public interest” — a term it has never precisely defined.

Under the Energy Policy Act of 1992, trades with countries that have FTAs with the U.S. are automatically considered “consistent with the public interest and granted without modification or delay,” according to the department.

Two bills introduced in the Senate in June would expand that blanket authorization to countries without FTAs, except those under U.S. sanctions: the License Natural Gas Now Act, proposed by Sen. Bill Cassidy (R-La.), and the Natural Gas Export Expansion Act, by Sen. Ted Cruz (R-Texas). Cassidy said his bill is supported by industry groups including the American Petroleum Institute and the Natural Gas Supply Association. IECA said it opposes the Cassidy bill.

Last week, DOE proposed automatic approvals of gas export applications of up to 140 Mcfd as long as the applications do not require an extensive environmental review.

DOE has delegated to FERC the authority to conduct environmental and safety reviews of proposed LNG facilities, but not to block exports on broader policy grounds.

Industrial Growth Threatened?

In April 2016, the American Chemistry Council (ACC) called the U.S. “the most attractive place in the world to make chemicals,” saying cheap gas was responsible for 264 U.S. chemical industry projects totaling $164 billion. By 2023, the group said, the spending would result in 69,000 new chemical industry jobs, 357,000 jobs in supplier industries and 312,000 jobs in neighboring communities. By contrast, IECA notes that LNG export terminals only employ a few hundred employees each.

Notably, 55% of the projects cited by the ACC were then in the planning phase, making them vulnerable to cancellation if gas prices rise too high.

Unlike IECA, however, the chemicals group expresses no fear of LNG exports.

The ACC told RTO Insider that it stands by its 2013 statement opposing any new export bans or restrictions on LNG export terminals and supporting “free-market policies that promote the export of American-made goods, including” LNG.

“Where there is not a clear consensus among the membership is on the question of whether the Natural Gas Act’s ‘public interest’ requirement should be further defined in export permitting to non-FTA countries,” the group said. It said its Executive Committee would continue discussions to seek a consensus and monitor “issues that could affect the competitive position of our industry in the future, such as infrastructure development and access to energy resources.”

The industrials group is aware that ACC’s position seems to undermine its concerns.

“IECA is often asked why other large manufacturing trade associations like the National Association of Manufacturers, the U.S. Chamber, the American Chemistry Council and the Business Roundtable do not raise concerns about excessive LNG exports,” it says. “The answer is that 100% of IECA member companies are manufacturing companies. Other trade associations have company membership which includes the oil and natural gas industry, and prevents them from addressing these concerns.”

According to EIA, power generation led the demand for U.S. natural gas in 2016, responsible for 36% of consumption. Industrial consumption was second (28%), with demand driven by petrochemical producers — who use natural gas as a feedstock in the production of methanol, ammonia and fertilizer — and other energy-intensive industries that use natural gas for heat and power.

EIA predicts gas use in power production will briefly decline because of growth in renewables and price competition with coal, before increasing after 2020.

The increase is based in part on the scheduled expiration of renewable tax credits in the mid-2020s. However, the reference case also included fuel switching to gas because of EPA’s Clean Power Plan, which President Trump has vowed to cancel. Natural gas consumption in the electric power sector is about 6% higher in the reference case in 2040 than the “No CPP” case.

Defining the ‘Public Interest’

Neither Congress nor the DOE has defined the “public interest” for making decisions on exports to non-FTA countries; instead, the department has used guidelines developed in 1984 for LNG imports, according to a 2014 Government Accountability Office report.

The industrials say the department should define the public interest to recognize job impacts. IECA says using natural gas in manufacturing creates eight times more jobs than exporting it. Domestic industrial use is worth twice the direct value added per year and 4.5 times the direct construction jobs, IECA says.

“The most glaring omission and failure of the Obama administration [public interest] studies was to cumulatively account for increased LNG exports to both NFTA and FTA countries. The studies only considered the impact for volumes to NFTA countries. More than twice the volume is approved for FTA countries and these volumes, in addition to domestic demand, were not included in any of the studies,” IECA said.

IECA Recommendations

The group recommends the government allow existing LNG export terminals approved for shipment to non-FTA countries to become operational and determine if the gas industry can increase production, pipeline transportation and storage capacity without price increases or supply shortages that would damage the U.S. economy.

“DOE should implement its authority under the Natural Gas Act (NGA) to establish a process of ongoing monitoring of economic impacts of LNG export volumes, and with the ability to reduce LNG export volumes for purposes of establishing a safety valve for U.S. consumers and the economic welfare of the country,” IECA said.

September 4, 2017

Power Sellers, LSEs Question CAISO ROR Designation

By Jason Fordney

Generation owners in CAISO are urging changes in an ISO reliability proposal for determining which unprofitable generators are eligible to receive payments in order to remain operational.

The power sellers were commenting on the ISO’s Capacity Procurement Model Risk-of-Retirement (CPM ROR) initiative, which is due to be reviewed by the Board of Governors on Nov. 1. The ISO is proposing to open timing windows each year — in April and November — for three types of ROR designations. (See CAISO Seeks Changes to Boost Retirement Program.)

CAISO risk-of-retirement ROR — Schedule for CPM ROR Implementation | *CAISO*

CAISO earlier this month included 20 changes to its revised straw proposal. It added a requirement for applicants in the April window to demonstrate that their resource is unlikely to receive an annual resource adequacy (RA) contract in early fall for the upcoming RA compliance year.

CAISO has proposed that a resource may not submit an ROR request in the April window unless its costs exceed the CPM soft offer cap. The ISO reasons that higher costs indicate the resource will likely not be chosen as an RA resource. It said it wants the CPM ROR payment to be based on cost of service and that the resource should be the only one that could meet an identified reliability need.

NRG Energy in its comments said the requirement effectively means that a resource with costs below the soft offer cap must wait until the November window.

caiso ROR Risk-of-retirement — NRG’s Encina Natural-Gas Fired Power Plant

“Forcing generator owners to wait until November to seek a CPM ROR designation effectively negates one of the primary reasons why resource owners sought a change in the ROR process, namely, to provide for a longer ‘runway’ with regards to seeking, and the CAISO evaluating and granting, an ROR designation prior to the end of a calendar year, to allow for better planning and coordination,” NRG said. “As a result, this new proposed requirement calls into question the value of this initiative.”

San Diego Gas & Electric said it did not believe that a resource’s costs need to be above the current CPM soft offer cap to receive a ROR designation.

“CAISO should not filter out less expensive but similarly qualified resources from the CPM ROR process,” the utility said, adding it sees no reason to keep more expensive resources online over less expensive ones. It said it supports requiring resources to justify costs even if below the soft offer cap.

Pacific Gas and Electric said it understands the CAISO position that the CPM ROR payment be based on cost of service.

“However, if a resource is granted a conditional CPM in April, it does not have an incentive to bid competitively when it knows it can receive cost-of-service recovery,” the company said in its comments.

Earlier this year, market participants said the CPM ROR initiative does not address the fact that CAISO’s energy market can no longer adequately compensate generation resources that are needed for reliability. (See CAISO Stakeholders Question Risk-of-Retirement Initiative.)

September 4, 2017

Consensus Fades on PJM Incremental Auction Solution

By Rory D. Sweeney

A consensus that appeared to be coalescing for how to revise PJM’s Incremental Auction process and address replacement capacity issues seems to have dissipated.

Stakeholders had been combining ideas into joint packages, but PJM’s Jeff Bastian announced at last week’s meeting of the Incremental Auction Senior Task Force that the packages had separated back into five individual proposals.

The first proposal from PJM staff focused on giving Base Residual Auction sellers confidence that their commitment can be replaced in an IA “with little likelihood of economic loss and in fact a high likelihood of profit.”

“We changed our proposal around quite a bit as we thought through this,” Bastian said. “It’s not the objective of this package to force the Incremental Auction clearing prices toward the clearing price … but it is the intent to correct what we think are existing design flaws which force just the opposite to happen, especially when it comes to the PJM sellback of excess.”

PJM BRA Incremental Auction MISO stakeholder process — Whitehead foregound; Steve Lieberman, AMP behind | © *RTO Insider*

GT Power Group’s Jeff Whitehead disagreed with PJM’s proposal to allocate excess commitment credits (ECCs) to load-serving entities.

“That logic ignores the fact that LSEs bear the risk of, and pay for, any excess capacity that underlies ECCs on behalf of their customers, and it is the terms of retail contracts with those customers that determine whether that excess capacity risk gets passed through to customers,” he said in an email to RTO Insider. “To the extent excess capacity risk is passed through by an LSE to its customers, then it follows that the proceeds associated with ECC sales should be passed through as well. If the excess capacity risk is not passed through to customers, and borne by the LSE, then it follows that the LSE would retain the proceeds of ECC sale. PJM’s proposal to not allocate ECCs to LSEs is unprecedented in that it incorrectly presumes the terms of retail contracts and deprives LSEs and their customers of the option to monetize the excess capacity for which they have paid.”

PJM argues that the current allocation system incents anyone looking to purchase replacement capacity to “hold out for a ‘better deal’ from a party that may be allocated ECC megawatts” rather than purchase PJM excess capacity during an IA.

Calpine’s David “Scarp” Scarpignato agreed with Whitehead’s argument, but pointed out that the allocations help the entire system. “When you get into individuals making decisions, that doesn’t work. It has to be a systemwide decision,” he said.

Whitehead agreed.

The Independent Market Monitor’s proposal is also focused on addressing IA clearing prices that are well below BRA clearing prices, but it differs on implementation. Both PJM and the Monitor envision just two IAs, with the RTO releasing capacity only in the final one. The current schedule has the BRA and three IAs for each delivery year. However, the Monitor would have the changes implemented with the third 2018/2019 IA, while PJM is targeting the 2021/2022 delivery year.

Direct Energy said it reintroduced its proposal based on concerns expressed at the IASTF’s last meeting. The package differs from PJM in that it puts a “collar” around the variable resource requirement (VRR) demand curve.

“With no collar, the possibility exists that all third-party suppliers sell at a price just below the BRA price, pushing any excess PJM [megawatts] out of the market,” Direct Energy’s proposal reads. “The result is that load still pays for the excess capacity and actually increases load’s scaling factors — increasing the overall cost of capacity.”

CPower’s Bruce Campbell offered a proposal “intended to maximize the benefit of Incremental Auctions to load interests with minimal changes to the current structure.” Described as “a compromise of stakeholder positions,” Campbell said it meets most of the preferences from initial polling, including maintaining three annual auctions between the BRA and the delivery year and having PJM sell excess capacity in each of them.

“My belief is that more supply will be coming from market participants than from PJM in future years. We’ve seen a lot of excess from PJM due to very high load forecasts in the BRA,” Campbell said. “I think PJM has taken substantive steps to address that, and I expect that most excess supply that’s available in Incremental Auctions will now come from market participants rather than PJM.”

The proposal offered by Gregory Pakela of DTE Energy Trading would set a different type of collar: a minimum sell offer at 50% of the BRA clearing price and a maximum at 100%. PJM would offer all its excess capacity in each of three IAs. Pakela offered research and analysis for his proposal, which led him to conclude, like Campbell, that PJM is unlikely to sell off a large quantity of commitments ever again. The corresponding reduction in sell offers will increase IA clearing prices, they say.

Scarp said the proposal neglected to account for the fact that capacity within a locational deliverability area must be replaced by other capacity in that LDA.

“PJM, I think, did a good job of addressing their sell offer, which everybody agrees is a major problem, probably the biggest problem,” Scarp said. “But there’s still other problems.”

September 4, 2017

FERC Again Rejects SPP’s Resource Adequacy Revision

By Tom Kleckner

FERC last week rejected SPP’s proposed Tariff revisions requiring load-responsible entities (LREs) to maintain sufficient capacity and planning reserves (ER17-1098).

The commission found SPP’s filing “inadequate in several respects” and said key elements must be addressed to help ensure successful implementation of a resource adequacy requirement (RAR).

Load-responsible entities LREs FERC — FERC’s offices in Washington, D.C.

At the same time, the commission offered the RTO guidance to help it “fully develop its proposal” for future submission. A quorum-less FERC in May also found SPP’s initial Tariff revision to be deficient. (See Waiting on FERC, SPP Members Cut Reserve Margin.)

“We expect to work with our stakeholders in assessing FERC’s suggestions,” Lanny Nickell, SPP’s vice president of engineering, said Friday. “We will continue efforts to incorporate a comprehensive set of resource adequacy requirements in our Tariff.”

SPP submitted the Tariff revision in March under Section 205 of the Federal Power Act. Nearly two dozen SPP members intervened in the proceeding.

In January, the RTO’s board and stakeholders approved a package of policies that included reducing its planning reserve margin from 13.6% to 12%, which translates to a 10.7% capacity margin. A task force spent more than two years developing the package, which is projected to reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)

Included in the package was a proposed Tariff revision stipulating that an LRE — an asset owner serving load in SPP’s markets — maintain sufficient firm capacity to serve its peak load and maintain a predetermined planning reserve margin.

Under the revision, an LRE’s net peak demand is defined as the forecasted highest demand for energy, including transmission losses, plus the volume of megawatts subject to firm power sales contracts. The revision defines firm power as power sales and purchases deliverable with firm transmission service, where the seller assumes the obligation to serve the purchaser’s load with capacity, energy and planning reserves that must be continuously available in a manner comparable to power delivered to native load customers.

FERC noted that it has previously ruled that power purchase agreements be backed by verifiable capacity in order to serve as capacity resources. It pointed to a 2008 order in which it said it did not consider a market participant’s statements “to be sufficient to constitute verification” and required that MISO be given a copy of a PPA to verify the capacity backing the agreement. The commission said SPP’s proposal lacked such requirements.

“As such, SPP’s proposal fails to ensure that LREs that rely on power purchase agreements are providing sufficient capacity to meet their net peak demand plus planning reserve margin on the same basis as LREs that self-supply their own capacity, and therefore could result in unjust, unreasonable and unduly discriminatory determinations of deficiencies and assessments of deficiency payments,” FERC said.

The commission also said SPP’s proposed treatment of firm power purchases and sales in determining net peak demand could result in undue discrimination. It pointed to intervenors’ arguments that if the purchaser under the contract is an LRE located in SPP, but the seller is an entity located outside the footprint, then no entity would have the obligation to demonstrate to the RTO that there is sufficient capacity and planning reserves to meet the load in SPP served by the firm power contract. It said that LREs that purchase from an external seller should be responsible for meeting SPP’s RAR for the load served by the purchase.

FERC also found that SPP did not show that its proposal to post publicly which LREs have not met their RAR to be just and reasonable, and said that SPP failed to provide justification for “creating a new information asymmetry between deficient LREs and potential sellers of capacity.”

The commission noted that SPP’s market for bilateral capacity is “relatively net long” compared to the 12% reserve margin.

“As the amount of uncommitted capacity and the number of potential sellers shrink over this period, concerns over the potential exercise of market power could arise,” FERC said.

September 4, 2017

Berkshire Companies Request EIM Rate Authority

By Jason Fordney

Berkshire Hathaway Energy subsidiaries PacifiCorp and NV Energy on Thursday asked FERC to lift bidding restrictions placed on them in the Western Energy Imbalance Market (EIM) and allow them to offer energy at market-based rates.

EIM FERC PacifiCorp Berkshire Hathaway Energy — PacifiCorp and NV Energy Filed with FERC for Market-Based Rate Authority in the EIM

In a joint filing with FERC, the companies said the bid limits are “no longer appropriate” because they both meet criteria for EIM participation established in previous commission orders (ER17-2392, ER17-2394). Both utilities are currently restricted to using a cost-based default energy bid (DEB) when offering into the market, which they told FERC is “both contrary to organized market design and presents risks of unrecovered costs in some market intervals.”

A November 2015 FERC order found that the Berkshire companies’ request for EIM market-based rate authority had included a “deficient” analysis that failed to disprove their horizontal market power. The order also questioned CAISO’s ability to mitigate such power outside its own balancing area.

In establishing the bid limits, the commission pointed to potential intertie constraints between NVE and CAISO, as well as between the PacifiCorp West and PacifiCorp East balancing authorities. Arizona Public Service is also separately subject to the bid limits.

The commission last year denied the companies’ request for rehearing on that decision, saying that future market power studies must provide analysis of potential power in EIM submarkets stemming from transmission constraints, not just the market as a whole. (See Berkshire Denied Rehearing on Market Power.)

The companies’ latest filing relies on analysis performed by Charles River Associates (CRA) showing that, since the entry of NVE into the EIM, there has been little congestion between balancing authority areas, so they should not be considered “sub-markets,” and that the ability of third-party resources to balance the system mitigates market power concerns. CAISO has also implemented market measures that mitigate prices back to the DEB when competing supplies cannot reach a constrained area, the Berkshire companies said.

According to the filing, the companies “are not asking to charge market-based rates without mitigation. Rather, their bids will be subject to the CAISO tariff-based mitigation instead of the current blanket, seller-specific mitigation.”

The Berkshire companies said the CRA findings are backed by an assessment produced by CAISO’s own internal Market Monitor, which in July said transfer capacity in the EIM footprint is now sufficient to justify removing bid limits that are in effect for PacifiCorp, NVE and APS. (See CAISO Monitor Says EIM Bid Limits No Longer Needed.) The Department of Market Monitoring said it would support the companies’ request to FERC for market-based rates.

PacifiCorp was the first utility to participate in the EIM when the market became operational in November 2014. NVE applied to join the EIM in March 2015 and began participation in December 2015.

PacifiCorp operates 71 thermal, hydroelectric, wind-powered generating and geothermal facilities in California, Idaho, Wyoming, Washington, Utah and Oregon. NVE subsidiaries include vertically integrated utilities Nevada Power and Sierra Pacific Power.

September 4, 2017

Clean Line Seeks Rehearing on Grain Belt Rejection

By Tom Kleckner

Clean Line Energy Partners has filed a rehearing request with the Missouri Public Service Commission, which earlier this month rejected the company’s request for a certificate of convenience and necessity for a portion of its $2.3 billion Grain Belt Express transmission project.

The company said Friday the request is a procedural step necessary to preserve the right to appeal the PSC’s decision to the state courts. It is one of several options Clean Line mulled over following the PSC’s second rejection in three years. (See Clean Line Ponders Options After Grain Belt Rejection.)

PSC FERC Grain Belt Express Clean Line Energy Partners — | *Clean Line Energy Partners*

“Clean Line continues to believe that the Grain Belt Express project is too important not to pursue and is therefore exploring many options to move the project forward,” Clean Line spokesperson Sarah Bray told RTO Insider. “The Grain Belt Express would be the largest clean energy infrastructure project in Missouri’s history and would save Missouri ratepayers more than $10 million annually.”

Four of the commission’s five members said in a concurring opinion Aug. 16 that the project is needed, economically feasible and beneficial to the public. However, they referenced a March state appeals court ruling on an unrelated case involving Ameren Transmission Company of Illinois, which found that infrastructure projects must first secure approvals from each county it crosses.

The project developers said the PSC’s decision that it could not “lawfully issue a CCN” until they could prove they had obtained the necessary county assents was in error. In their filing, they asserted the appeals court ruling interprets a statutory provision that was never invoked in and is not relevant to this case, and that “there are particular legal and factual distinctions” between the two cases.

“The commission’s findings of fact and conclusions of law are not supported by substantial and competent evidence on the record as a whole and are grounded in legal error,” the filing contends.

Clean Line was unable to gain permission to construct the line through Caldwell County. However, the project has approvals from all other Missouri counties and from the neighboring states of Kansas and Illinois.

The project would deliver approximately 4,000 MW of wind power from western Kansas through Missouri and Illinois to the Indiana border over 780 miles of HVDC lines. Clean Line expects the Grain Belt Express to enable about $7 billion of new, renewable energy projects to be built.

September 4, 2017

PJM Stakeholders Hash out Capacity Repricing Triggers

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM appears headed toward implementing a capacity construct that would reprice auction results to address the influence of subsidized generation offers.

The RTO’s Capacity Construct/Public Policy Senior Task Force (CCPPSTF) met last week for the sixth time in August to focus on determining what circumstances would trigger auction repricing.

Repricing, which would filter subsidized offers out of auction results to mitigate suppression of the clearing price, is a key mechanism in five of the nine capacity redesign proposals. NRG Energy, LS Power, Exelon, PJM and Old Dominion Electric Cooperative all included it. (See Stakeholders Seek to Trim PJM Capacity Construct Options.)

CCPPSTF attendees have identified 18 components that the repricing trigger should address, including a subsidy’s financial significance in supporting a resource and the scale of a resource’s impact on the market. The discussion has delved into the details of how states could potentially issue subsidies, including through yearly allotments or a one-time lump-sum payment for performance over an expected lifespan.

Sorting the Details

Avangrid’s Kevin Kilgallen suggested that repricing should be triggered only by subsidies provided during an auction’s delivery year. Calpine’s David “Scarp” Scarpignato added that lump-sum subsidies that include the delivery year in their amortization should also be a trigger. The distinction was initially lost on some participants.

“There are two different issues here,” Kilgallen said. “I’m saying only subsidies that may or will be or are expected to be applicable during the delivery year should be considered. … I think [Scarp’s is] a separate issue, whether or not there’s a trigger for a resource that may or may not receive [in that year] a subsidy that it’s eligible for.”

PJM FERC Capacity Construct — Guerry | © *RTO Insider*

Scarp later suggested that subsidies that incentivize the pricing of carbon emissions should be exempted. EnerNOC’s Katie Guerry questioned the suggestion as ostensibly supporting a controversial tenant of Exelon’s proposal that would effectively exempt nukes that are receiving subsidies from triggering repricing. Scarp clarified that his suggestion was specific to subsidies that would monetize emissions instead of subsidize units that have a related beneficial attribute, such as being emissions-free. His proposal wouldn’t exempt a unit that received a subsidy elsewhere, he said.

Guerry said carbon pricing creates an entirely separate market that’s not involved with the capacity market.

“Carbon pricing is something completely separate, and it’s in and of itself a solution … that would obviate the need to do anything in the capacity market,” she said. “If you have something like carbon pricing, there’s not a question of exempt or not exempt. It’s the solution that we pursued outside of the capacity market.”

Scarp pointed out that subsidies could affect either the capacity or the real-time energy markets, which introduced a new concept for the group as all discussion had previously focused only on subsidies in the capacity market.

“If PJM institutes carbon pricing, you don’t think it will affect your energy [market] revenues? It will,” Scarp said.

State Actions Only

Stakeholders also debated whether a resource that received a subsidy in the past should always be considered subsidized, and whether federal subsidy programs should remain outside the CCPPSTF’s scope.

While the task force’s charter is limited to state programs, Exelon’s Jason Barker asked if PJM’s eventual FERC filing on the issue would also remain limited to state programs. PJM’s Dave Anders, who facilitates the group’s meetings, declined to speculate about the RTO’s plans.

“The problem statement we’ve got is limited strictly to state actions. What happens at FERC, happens at FERC,” he said.

Direct Energy’s Marji Philips argued that federal actions weren’t the issue.

“The difference between a federal action is all states are impacted by it and have to price it in,” she said. “If it’s a state law, it only impacts — or should only impact — the citizens of that state, and that’s what this exercise is. It’s not to tell a state what it can or can’t do. It’s to make sure that other customers from other states don’t pay for what one state wants that another state might not want.”

Exelon’s Sharon Midgley responded that such programs can still impact auction prices. “While a federal program may have the same impact across the entire footprint, it still has the potential to suppress [prices, even if it does so] uniformly,” she said.

Stakeholders are also considering how to write rules that address potential future scenarios in which states decide to offer financial incentives for demand-side resources or certain existing programs expand to other states, such as the Illinois program offering zero-emissions credits to nuclear units.

“I think there are a number of parties who would say, ‘I’m OK with the status quo. My concern is what’s coming down the pike,’” Guerry said. “Preference for the status quo by some might be dictated by what happens or may not happen in the future.”

‘Non-repricing’ Alternatives

While the meeting focused on repricing, stakeholders have also suggested additional redesigns beyond the five repricing proposals. The Independent Market Monitor has proposed extending the existing minimum price offer rule indefinitely to any subsidized unit that doesn’t qualify for several specific exemptions.

Three “non-repricing” proposals would reduce the role of the auction in PJM’s capacity acquisition procedures. John Horstmann at Dayton Power & Light proposed to expand the RTO’s existing fixed resource requirement (FRR) option to allow utilities to meet capacity obligations with any combination of FRR and auction results.

A proposal by the Sustainable FERC Project would reduce the capacity requirement to off-peak season needs and allow seasonal resources to account for the additional demand during the peak season. American Municipal Power (AMP) is still finalizing the details of a proposal that would emphasize the use of long-term bilateral contracts over a single auction.

Polling Controversy

With his company’s proposal unfinished, AMP’s Ed Tatum expressed concern about a planned PJM poll to measure the relative popularity of the proposals. He was particularly displeased with an opening section that asked respondents to opine on how each proposal addressed specific issues.

“Is this something we’re going to do regardless of how people feel about it?” Tatum asked. “It looks like you’ve got 11 good questions. The first one is a bit broad and the categories elusive. … We need to make sure the poll results are meaningful and we’ll get something good and useful out of it.”

“We are trying valiantly to get some additional information out to people to see what people are thinking,” Anders said. “I feel like we’re in full attack mode against this poll before we’ve even seen it.”

Tatum was not alone in his concerns about the poll. Barker noted that the poll doesn’t address repricing triggers, “which is quite possibly the most important part, which is why we’ve registered our concerns.” As part of his instructions to stakeholders at the end of the meeting, Anders later asked those who submitted proposals to attend the next meeting prepared to define the triggers they plan to include in their proposal.

GT Power Group’s Tom Hyzinski requested adding to the first question whether each proposal “insulates other states or other jurisdictions against the actions of a state, because I think there’s only one that actually does that, and that’s the IMM’s proposal. Any of the others, there’s actions that can be taken in one small place that affect the pricing and market signal in every other section of PJM.”

Barker said that Hyzinski was “pretty shrewd” to provide his answer with the question.

“Similarly, we could ask for questions about whether or not the application [of the proposal] is discriminatory, much like the IMM’s proposal, where it proposes to exempt certain resources but not others that may have the same dollar-for-dollar impact,” Barker said.

Anders said that he is anticipating at least one more round of polling and feedback before moving to a recommendation vote. “We’ll just have to see how things mature after [the polling],” he said.

PJM staff planned to distribute the poll to the CCPPSTF task force list last week and differentiate between member and non-member responses. Staff are seeking to receive responses this week in order to prepare results for the next CCPPSTF meeting on Sept. 11.

September 4, 2017

FERC Rejects CAISO Small TO Interconnection Plan

By Jason Fordney

FERC on Friday voted 2-1 to reject a CAISO proposal intended to prevent small transmission owners from shouldering the costs for network upgrades needed to interconnect generation serving load outside of their service territories.

The proposal was designed specifically to address the circumstances of Nevada-based Valley Electric Association, the California grid operator’s only out-of-state member. The electric cooperative serves 45,000 customers and peak demand of 135 MW within a 6,800-square-mile territory straddling the California-Nevada border.

CAISO FERC transmission owner interconnection plan — | *Valley Electric Association*

FERC’s decision means Valley Electric’s ratepayers potentially face the cost of interconnecting almost 4,000 MW of solar resources that would help support California’s renewable portfolio standard. The cooperative has 25 requests totaling 3,952 MW of new capacity in its interconnection queue.

CAISO conducted a seven-month stakeholder process to develop the proposal to certify Valley Electric as a small participating transmission owner (PTO) and distribute its interconnection costs across the broader ISO. (See Board Approves CAISO Small TO Generator Interconnection Plan.)

The rule changes would have folded low-voltage generator interconnection costs into high-voltage transmission revenue requirements, spreading costs among the ISO’s entire ratepayer base. San Diego Gas & Electric had cited a concern that CAISO’s solution did not meet FERC cost allocation rules and Southern California Edison opposed the proposal.

“In the past, CAISO has justified its cost allocation methodology by explaining, with supporting evidence, that low-voltage facilities generally support local service and that the high-voltage transmission facilities perform a backbone function that supports regional flows of bulk energy,” FERC said (ER17-1432).

The ISO was now asserting “without supporting evidence” that low-voltage upgrades on Valley Electric’s system — but not those on the systems of Pacific Gas and Electric, SCE and SDG&E — benefit customers throughout the region, the commission said.

“CAISO’s proposal is inconsistent with the commission’s cost causation principles because it shifts costs from a single PTO to all load in CAISO without providing evidence that CAISO transmission system users being allocated such costs benefit from the network upgrades to Valley Electric’s low-voltage transmission system,” FERC said.

“Of additional concern is CAISO’s proposal to allow stakeholders to decide whether to grant alternative certified small PTO rate treatment; stakeholders are interested parties that may be impacted by the determination that a PTO should become a certified small PTO.”

Commissioner Cheryl LaFleur dissented in the ruling.

“It is simply unfair to require the 0.27% of CAISO’s customer base in Nevada to bear the costs of these interconnections, which are not remotely commensurate with the benefits they receive,” she said. “Rather, I believe the customers in California, whose policies are driving the costs, should largely bear the burden of these costs. The CAISO proposal achieves that objective in a pragmatic way.”

In June, FERC staff sent CAISO a deficiency letter asking for a better definition of CAISO’s criterion for designating a certified small PTO and how transmission customers will benefit from low-voltage interconnection network upgrades in Valley Electric’s service territory.

CAISO did not immediately respond to a request for comment. In comments previously filed with FERC, the ISO said Valley Electric faced the risk of being allocated all of the costs for network upgrades necessitated by other utilities’ procurement efforts, and that similarly situated small TOs potentially could face the same situation.

September 4, 2017

Public Utility Commission of Texas Briefs: Aug. 31, 2017

The Public Utility Commission of Texas last week gave preliminary approval to Oncor’s and Sharyland Utilities’ proposed swap of $400 million in assets.

The order lists a set of 27 issues to be discussed before the PUC renders a decision, which is due by Feb. 1, 2018 (Docket 47469).

Oncor and Sharyland filed a settlement agreement early last month, asking the PUC to expedite the case by deciding it without referring it to the State Office of Administrative Hearings (SOAH). The companies said Sharyland’s current retail customers will receive “substantial rate relief” under the transaction, in which Sharyland will take over 258 miles of 345-kV transmission from Oncor in exchange for Sharyland’s distribution network and retail delivery customers.

“The hard work that’s gone into this is going to significantly change people’s lives,” said Commissioner Brandy Marty Marquez. “I’m happy this is all proceeding.”

Among those signing on to the settlement agreement are commission staff, the Office of Public Utility Counsel (OPUC), the Steering Committee of Cities Served by Oncor, the Alliance of Oncor Cities, numerous other Texas cities and various electric retailers. The Texas Industrial Energy Consumers (TIEC), the Targa Pipeline Mid-Continent WestTex and Golden Spread Electric Cooperative chose not to oppose the settlement.

An administrative law judge set Tuesday as the deadline to request a hearing in the docket.

The settlement would also resolve Sharyland’s separate applications to deploy an advanced metering system (Docket 44361) and requests for rate relief and a certificate of convenience and necessity (Docket 45414), and Oncor’s application to change its rates (Docket 46957).

ERCOT AEP SWEPCO PUCT — PUCT Commissioners Anderson (left) and Marquez | © *RTO Insider*

“This will ultimately solve a lot of problems for a lot of folks,” said Commissioner Ken Anderson.

Commissioners Undecided on LP&L’s Contested-Rate Case Request

The PUC postponed a decision on how to process Lubbock Power & Light’s request to move 430 MW of its load from SPP into ERCOT. The commission is considering whether to treat the request as a contested case or refer it to SOAH, where it would be heard before an ALJ.

The commissioners will announce their decision during their Sept. 28 meeting, after reviewing a draft preliminary order (Docket 45633).

“I’m fine going to SOAH,” Anderson said. “The other tradeoff, in terms of time, is SOAH may be able to handle getting the facts. It handles much of discovery anyway.”

“If we send it to SOAH, the judge won’t do much of anything until the preliminary order comes out,” Marquez said.

LP&L is hoping for a decision before March 2018, which will enable it to maintain its plan to integrate with ERCOT by June 2021. The municipality announced its intention in 2015 to disconnect its load from SPP and join ERCOT in June 2019. That that date has since slipped, but LP&L extended a power purchase agreement with Southwestern Public Service through May 2021.

The preliminary order will allow the PUC to decide policy questions over load migrations “by putting a framework around what needs to be decided,” Anderson said.

“A ‘Hotel California’ clause in the order might be appropriate,” he said, referring to the Eagles’ lyric, “You can check out any time you like, but you can never leave!”

“Going back and forth between ERCOT and other regions is, at best, disruptive, not to mention expensive,” Anderson said.

ERCOT, SPP Agree to Rayburn Country Migration Studies

Rayburn Country Electric Cooperative representatives told the commissioners they are comfortable with ERCOT’s and SPP’s proposed scope and timeline for their studies of the East Texas co-op’s proposed transfer of much of its SPP transmission facilities and load into ERCOT (Docket 47342).

The grid operators said they would conduct individual studies using a common scope and assumptions, including an analysis of system impacts, expected changes in production costs and avoided projects. ERCOT and SPP also plan to conduct a reliability review of the transfer using power flow and system contingency analysis.

ERCOT and SPP said they expect to complete their studies on the move by February.

“It’s time to get started,” Marquez said.

Rayburn Country is an SPP member, but only about 150 MW (less than 20% of its load) and 160 miles of its transmission sit in the Eastern Interconnection. ERCOT has said it will cost $38 million to connect the SPP load with the Texas grid.

SWEPCO Seeks to Reduce Wind Catcher Costs

The commissioners consented to a list of 36 issues to be contested before an ALJ related to Southwestern Electric Power Co.’s costs associated with parent American Electric Power’s massive Wind Catcher project. (See AEP to Spend $4.5B on Largest Wind Farm in US.)

SWEPCO has filed a request with the PUC (Docket 47461) that its costs associated with the Oklahoma wind farm and EHV transmission line — $2 billion and $1.1 billion, respectively — be treated as an eligible fuel expense, and that the federal production tax credit be treated as a credit against it. The utility has estimated $1.1 billion is jurisdictional, and it wants to credit the PTC’s value against its fuel expenses, until the project can be included in base rates.

SWEPCO also wants to defer for ratemaking purposes a portion of the PTC into a regulatory liability that would be credited back to ratepayers 11 years after Wind Catcher’s planned 2020 in-service date. This would avoid a large increase in rates once the PTC expires, the company said.

The PUC referred SWEPCO’s request to SOAH early last month. OPUC, TIEC and Golden Spread have filed motions to intervene and contributed to the list of issues. That list includes accounting and cost allocation questions and whether SWEPCO needs the additional capacity.

AEP plans to build 350 miles of 765-kV lines to connect the 2,000-MW wind farm in the Oklahoma Panhandle to its SWEPCO and Public Service Company of Oklahoma subsidiaries. SWEPCO services northeastern Texas. The wind farm would be the largest in the nation.

— Tom Kleckner