WASHINGTON — President Trump’s nominee for FERC chair brought little comfort to Republican senators seeking assurances that, under his leadership, the commission would look into shoring up uneconomic coal plants.
“FERC is not an entity whose role includes choosing fuels for the generation of electricity,” Kevin McIntyre, cohead of law firm Jones Day’s global energy practice, said at his Senate Energy and Natural Resources Committee confirmation hearing Thursday. “FERC’s role, rather, is to ensure that the markets for the electricity generated by those facilities proceed in accordance with law.”
McIntyre was responding to a question from Sen. John Barrasso (R-Wyo.), who asked if he agreed with acting Chair Neil Chatterjee’s belief that so-called baseload power — coal and nuclear plants — needed to be “properly compensated” to recognize their value to “reliability and resilience.” (See Coal Seeks ‘Resiliency’ Premium; FERC ‘Fuel Wars’ Coming?)
“I think, overall, the FERC’s role should be to take a hard look at these very important questions and determine where FERC’s jurisdiction actually gives it a role in making decisions that could ensure that there’s a proper attention to the reliability and resilience impacts of what is traditionally thought of as baseload generation,” he said.
Later, Sen. Angus King (I-Maine) urged McIntyre to “just go with the science” when it came to baseload generation, expressing concern that the term had become politicized.
“FERC does not pick fuels among different generating resources,” McIntyre responded. “And so it’s important that it be open to, as you say, the science, which I would expand somewhat also to include the characteristics of reliability and the characteristics of economics.”
The other nominee being considered for the commission, Richard Glick, echoed McIntyre’s position. He told Barrasso that a recent U.S. Energy Department study of the electric grid determined that the loss of baseload generation had not impacted reliability, “but they also suggested it was something to keep an eye on and look for in the future.”
“So I think both FERC and the Department of Energy need to keep an eye on it and continue to study the matter,” said Glick, currently general counsel for the Democrats on the Senate committee.
The committee devoted less than half of the two-hour hearing to McIntyre and Glick, as it also considered two nominations to the Interior Department: Ryan Nelson to be solicitor, and Joseph Balash to be assistant secretary for land and minerals management. The committee’s senators — some hailing from states with large swaths of federally owned land and sizable Native American populations, such as Alaska, Arizona, Nevada and New Mexico — had plenty of questions for the two Interior nominees about policies important to their constituents.
The two FERC nominees, on the other hand, found themselves declining to provide specific answers to many questions, citing ongoing proceedings and Notices of Proposed Rulemaking before the commission. Those questions covered issues such as price formation in energy markets, and eliminating barriers to distributed energy resources and energy storage.
Several Democratic senators asked the nominees about states’ rights in enacting renewable portfolio standards. After discussions with the Interior nominees about her home state, Sen. Catherine Cortez Masto (D-Nev.) asked McIntyre and Glick for quick, yes-or-no answers to her questions.
“Do you agree that states have the authority to establish the resource mix that best serves their customers?” she asked, to which the nominees responded in the affirmative.
She also asked if they agreed that renewable resources can be reliably integrated. Glick noted that several states get at least half of their electricity renewables and that none have had any problems.
“In part due to actions taken by the FERC, renewable energy resources are making their way reliably to our grid,” answered McIntyre.
Noting her state’s adoption of a zero-emission credit program, Sen. Tammy Duckworth (D-Ill.) asked if they agreed that states were “the appropriate place for these types of policies to be decided.”
“We do have a federal system of law,” McIntyre responded. “FERC has its role and the states have theirs, and there’s no question that the states have the absolute right to implement these renewable portfolio standards.”
Committee members refrained from addressing some of the more controversial issues brought up during the May confirmation hearing for Chatterjee and Commissioner Robert Powelson — such as climate change and the Public Utility Regulatory Policies Act. (See No Fireworks for FERC Nominees at Senate Hearing.)
Duckworth did ask about FERC’s role in securing a cleaner environment. Both nominees asserted that FERC is not an environmental regulator, while also noting that the commission ensures that clean resources have nondiscriminatory access to the markets and that it is seeking to better integrate DER, storage and demand response.
Committee Chair Lisa Murkowski (R-Alaska) told reporters after the hearing that she hopes to advance McIntyre and Glick to the full Senate “late next week.” Their confirmation would restore FERC to a full, five-member slate — which it has been without since the departure of Philip Moeller on Oct. 30, 2015.
WILMINGTON, Del. — Sempra Energy moved a step closer to acquiring Texas utility Oncor after a U.S. bankruptcy judge on Wednesday approved the $9.45 billion agreement (14-10979).
The deal would give Sempra an 80% stake in the rate-regulated operations of the largest transmission and distribution utility in Texas. The deal must still be approved by the Public Utility Commission of Texas.
The utility has been the subject of a series of failed takeover bids since parent Energy Future Holdings, saddled with almost $50 billion in debt after poor bets on energy prices, declared bankruptcy in April 2014.
EFH announced the deal with Sempra three weeks ago in the same Delaware courtroom, after hedge fund Elliott Capital Management — the largest holder of EFH bonds — opposed as too low a $9 billion all-cash offer by Berkshire Hathaway Energy. Including debt, Berkshire’s bid valued Oncor at $18 billion, while Sempra’s values the utility at $18.8 billion. (See Sempra Outmuscles Berkshire for Oncor.)
‘Largely Consensual’
“Unlike any proposal we’ve had in the past, this proposal has the support of one of the debtors’ largest and most active creditors,” Chad Husnick, an attorney representing EFH, told Judge Christopher Sontchi. “The Sempra transaction is the highest and best available transaction.”
Husnick said the Sempra deal was “largely consensual” and prompted just one objection regarding how creditors would be compensated, a consideration that Sontchi said should be reserved for a confirmation hearing. That hearing would take place after the PUCT approves the deal.
“We’ll try it again,” Sontchi said in approving the documents, drawing laughter from the courtroom.
Sempra said it is committed to ensuring that Oncor remains independent, financially strong and based in Dallas with local management.
“Oncor is a well-managed, top-tier utility, operating in one of the strongest U.S. growth markets. We believe it will be an excellent strategic fit with our portfolio of utility and energy infrastructure businesses, while opening up a new avenue for our long-term growth,” Sempra CEO Debra Reed said in a statement after the hearing.
The acquisition would allow Sempra to regain a foothold in Texas, where it once owned and operated 10 power plants and still maintains a 200-person Houston office to support marketing and development activities. (See Sempra Begins ‘Listening Tour’ of Key Stakeholders.)
| Sempra Energy
With the approval in hand, EFH set an Oct. 30 voting deadline for its plan. EFH approved the deal in part because Sempra was willing to accept ring-fencing of Oncor — giving it independence from its corporate parent — and no assurance that it will get control of the 20% of Oncor now owned by Texas Transmission Holdings Corp.
Sempra is the fourth would-be suitor for Oncor. Dallas’ Hunt Consolidated and Florida-based NextEra Energy saw separate bids fall apart in the face of the Texas PUC’s calls for strict ring-fencing measures and a requirement that Oncor be run by a “truly independent” board with control over decisions on capital expenditures and operating expenses.
NextEra Termination Fee Battle
Wednesday’s hearing also addressed EFH’s upcoming legal battle with NextEra, which had offered $18.7 billion for Oncor but failed to win approval for the deal from the PUCT. EFH accused NextEra of failing to do its best to receive approval and sued the former suitor earlier this year to prevent any attempt by NextEra to claim the deal’s $275 million termination fee. The trial is set to begin next April.
EFH filed for Chapter 11 protection in 2014 with roughly $42 billion in debt, which was then the eighth-largest bankruptcy in U.S. history. About $25 billion of the debt has been restructured by spinning off subsidiary Texas Competitive Electric Holdings, which split the company in half.
CARMEL, Ind. — MISO’s proposed multimillion-dollar spend to upgrade — and then replace — its market platform will yield a nearly threefold return within 12 years, stakeholders heard this week.
The $130 million invested to extend the current system and implement a new platform would reap $341 million in net benefits by 2030, MISO Vice President of System Operations Todd Ramey said during a Sept. 6 workshop in which RTO officials laid out the business case for replacing the system.
MISO’s Board of Directors in June approved the first phase of the upgrade, enabling the RTO to commit $65 million to lengthen the life of its current market platform by at least five years. Another $65 million will be needed to create a new, modular market platform, the final design for which is slated to emerge in 2019. (See MISO Sets Target for Market Platform Upgrade Decision.)
Countdown to Obsolescence
Since 2005, MISO has spent about $350 million to develop and expand its market system, which was built using technology from the 1990s. The RTO predicts it has five to seven years before evolving cybersecurity standards and increasing market complexity render the system obsolete, no longer able to clear the day-ahead market. Current vendor General Electric also plans to end support for the existing platform around that time.
Early-stage prototypes of the new computer system will be released in 2018 and 2019 for stakeholder scrutiny, said MISO Executive Director of Market Design Jeff Bladen. The RTO will begin to swap out market components by 2020 and fully migrate to the new modular computer system by 2023, he said.
“The goal is for a modular system … that is much less brittle than the existing system,” Bladen said, adding that the new system will shed the “hub and spoke” software format of the current system in favor of a “data integration layer” that can run several applications simultaneously while isolating the impacts of market changes so other programs are not affected.
Bladen said MISO’s current system cannot accommodate the “plausible” scenario in which hundreds of storage assets begin participating in the market over the next few years. It’s also unable to manage the “added scale and added scope of the existing market, let alone the security posture we would like to have as we look over the horizon,” he said.
The current system also cannot support some planned market enhancements — such as a price spread product, which will have to wait for the future platform, Ramey said. MISO expects the need for new ancillary services — including the recent additions of enhanced combined cycle modeling, a ramp capability product and extended locational marginal pricing — to only increase in the future.
“In a world where resources will continue to multiply and resource size will continue to decrease, the ability to handle more of them and in a more automated fashion” is a must, Bladen said.
Big Effort
Bladen said MISO is currently assembling a team of employees led by Ramey to oversee the replacement.
“This is going to be at least as big an effort as the original market roll-out,” he said.
MISO plans to issue a request for proposals for a system replacement this month. The RTO is looking for a resilient platform that can handle an evolving energy portfolio with increased energy storage and distributed energy resources, possible footprint expansion and future market products — and include security that can stand up to cyber threats, according to Bladen.
| MISO
Under the near-term preserve-and-protect plan, MISO “is going to wring the very last degrees of usefulness out of the current system,” Bladen said.
Indiana Utility Regulatory Commission staffer Dave Johnston asked if the platform changeover would require MISO’s Independent Market Monitor to upgrade its own software. The Monitor has functions that run alongside MISO’s day-ahead market to enforce market mitigation when necessary.
Bladen conceded the possible need for an upgrade in order to ensure the IMM’s continued operation. And although “it’s very early in the process,” the Monitor’s IT staff may begin to work with MISO staff on the issue, he said.
MISO will convene another stakeholder workshop in late October to discuss how RTO members’ current software might interact with a new market platform, Bladen added.
Customized Energy Solutions’ David Sapper urged MISO to share regular updates with the stakeholder-led Finance Subcommittee. “They’ve all signed nondisclosure agreements, and MISO can be candid with them,” Sapper said.
MISO would consider that option, along with possibly providing updates to the Market Subcommittee, Bladen said.
RTO officials will also later this month provide the board with a project status report during a board meeting in St. Paul, Minn.
“We’re going to have an ongoing conversation going forward,” Bladen said. “We will take any feedback you have on the work we’ve done so far.”
PJM’s proposal to create standardized contracts for establishing dynamic transfers with other balancing authority areas has provoked opposition from market participants, a neighboring ISO and the Independent Market Monitors for both PJM and MISO.
Critics of the proposed pro forma agreements for pseudo-tied resources filed protests with FERC over the past week — each with a different complaint (ER17-2291).
PJM and MISO both received stakeholder endorsement for their plan to establish agreements that would impose standard requirements on external units seeking to deliver power into PJM. The grid operators filed relevant revisions to their joint operating agreement on Aug. 1 (ER17-2218, ER17-2220).
MISO received conditional approval of its agreement from FERC on Aug. 9, although the plan has since been protested by American Municipal Power. PJM’s proposal includes separate agreements for pseudo-ties and dynamic schedules and was filed with FERC on Aug. 11. (See MISO-PJM Markets Meeting Addresses Seams Issues.)
‘Adverse’ Impacts
In its protest, NYISO said it “is prepared to work with PJM to develop a mutually acceptable alternative,” arguing that the current proposal “will likely cause adverse reliability impacts” and “exacerbate interregional seams.” It said PJM’s proposed pseudo-tie rules, which would require all dispatch control to be transferred to PJM from the RTO or ISO where the unit is located, “are fundamentally incompatible” with several NYISO practices, including financial transmission reservations, generator scheduling market rules and reliability operating standards. The rules would also conflict with the grid operators’ interregional agreement and NYISO’s Tariff, the ISO said.
The New York grid operator said PJM shouldn’t be allowed to standardize pseudo-tie requirements. Any agreement should be “sufficiently flexible to accommodate regional differences at its borders” and require approval from the native balancing authority, it said. Under PJM’s current plan, the native BA would only have to acknowledge awareness of the agreement between PJM and the unit but wouldn’t have to be a party to it.
At recent stakeholder meetings, PJM staff have said they attempted to develop the agreements with input and endorsement from NYISO, but that the neighboring ISO refused to cooperate. Staff decided to move forward without NYISO’s involvement.
While recognizing that PJM has attempted to address previous concerns, MISO Monitor David Patton contended that the plan still creates “substantial economic and reliability harm to the customers in [MISO and PJM] areas and [provides] no countervailing benefit that cannot be achieved by other means.”
PJM’s requirement of operational control creates a problem, he said, because the BA “most impacted by the generator and responsible for the generator interconnection and local impacts loses control of commitment and dispatch.”
PJM Monitor Joe Bowring also filed comments opposing PJM’s plan for operational control — but for the opposite reasons. He called the proposal “an improvement over the existing rules” but said it “needs to be substantially strengthened” because issues the Monitor has pointed out before “remain and are amplified.”
Bowring reiterated an argument he’s brought up repeatedly at stakeholder meetings: that the rules should be designed so that pseudo-tied units can serve as “complete substitutes” for capacity resources within the RTO’s footprint. As such, he argued, the native BA should not be able to recall the unit. Otherwise, pseudo-tied units shouldn’t be eligible to be capacity resources. The agreement would allow native BAs to supersede PJM’s control during two emergency conditions.
Bowring’s filing requests removal of that exemption, along with allowances for suspension or termination of a pseudo-tie.
The provisions create “substantial uncertainty as to whether a pseudo-tied external capacity resource can be available and under the dispatch control of PJM when needed. As a result, pseudo-tied external capacity resources cannot be considered a complete substitute for internal capacity resources,” he said. “If external capacity resources cannot be full substitutes for internal capacity resources, they are inferior products and should not be permitted in the PJM capacity market because they will suppress the price for internal resources and result in an inefficient market outcome.”
Other Protests
Several municipal power organizations, cooperatives and transmission companies also filed protests. Like Bowring, Cogentrix Energy Power Management supports standardizing pseudo-tie rules but opposed the suspension and termination provisions.
“PJM should not be permitted to suspend or terminate a pseudo-tie on any lesser basis than it may suspend or terminate an internal generator’s interconnection rights,” Cogentrix wrote.
The generator, which owns a pseudo-tied unit in Tilton, Ill., also took issue with what it believes is an insufficient transition period and argued that a pseudo-tie should have just one comprehensive agreement among RTOs. PJM’s proposal — which stemmed from the inability for PJM and MISO to agree on terms — would require a unit to obtain separate agreements with each grid operator for the same pseudo-tie.
The Illinois Municipal Electric Agency argued that the proposal is the most recent in a series of changes that has made it “increasingly more difficult and more costly” for IMEA to use its generation units in MISO to self-supply its customers in PJM. The border situation developed in 2004 when Commonwealth Edison migrated from MISO to PJM.
“Like erosion at a beach caused by a succession of waves, each new set of restrictions imposed by PJM, culminating with the current pseudo-tie ‘wave,’ contributes to the erosion of IMEA’s statutory protections,” IMEA staff wrote.
IMEA also contended that its type of pre-existing exception should be grandfathered.
The Northern Illinois Municipal Power Agency said that units with existing pseudo-ties shouldn’t be subject to PJM’s proposed administrative fees in signing the standardized agreement. The agency serves load in PJM but has an ownership stake in a generation resource in MISO that is partially pseudo-tied.
AMP’s protest acknowledged that it endorsed a previous version of the proposal, but that the filed version doesn’t resolve all pseudo-tie issues as it purports to. The utility criticized the filing as “one more piecemeal effort to address these issues” and requested several changes on indemnification, agreement termination and authority to determine payments.
North Carolina Electric Membership Corp. took issue with PJM “unmooring” the agreement from the RTO’s Tariff definition of long-term firm point-to-point transmission service. PJM has previously attempted to impose a five-year service requirement for pseudo-tied units that goes beyond the one-year requirement in the Tariff, and the co-op expressed concerns the RTO might use the agreement to lengthen the requirement if it is not linked to the Tariff definition.
Several intervenors urged deferring a decision on the agreements until other dockets focused on pseudo-ties have been addressed. Patton estimated there are “at least” 10 such proceedings and seconded MISO’s request for a technical conference on the issue.
“Determinations by the commission in those other dockets will invariably affect evaluation of the changes proposed in this proceeding,” he wrote.
Several of those dockets are complaints regarding double assessment of congestion management charges (EL16-108, EL17-29, EL17-31). PJM and MISO have developed a solution that they believe addresses the problem and will be seeking stakeholder endorsement in two phases.
ISO-NE hopes to open a window in November for Maine wind generators interested in joining a cluster interconnection system impact study. The RTO filed its proposed clustering methodology for FERC approval on Sept. 1, requesting approval by Nov. 1 (ER17-2421).
The filing culminates an 18-month effort to assess new 345-kV AC transmission circuits that could connect to areas in northern and western Maine with the largest number of requested new generation interconnections. (See ISO-NE to Offer Clustered Interconnection Requests in Maine.)
System Planning Director Al McBride presented a description of the filing and the study plans at Wednesday’s Planning Advisory Committee meeting.
The clustering approach will involve two phases: a regional planning study, followed by a cluster system impact study of multiple projects that will share the costs for common upgrades.
The Maine Resource Integration Study will be used as the regional study for the first two clusters being considered for development:
A radial double-circuit 345-kV AC line between the Maine Yankee generating plant to a new substation at Pittsfield, with a new 345-kV line and three additional substations north of Pittsfield and ending near the Canada border. The estimated cost is $1.31 billion.
A radial 345-kV AC line north of the Larrabee Road substation to near the New Hampshire border at an estimated cost of almost $521 million.
The estimates include a shared cost of $108 million for a new 345-kV line from Coopers Mills to Maine Yankee (line 392) that is needed by both radials. Costs would be allocated using the distribution factor methodology or the late-comer cost allocation rules.
ISO-NE plans to study two clusters of transmission upgrades to enable the connection of more wind generation in western and northern Maine. | ISO-NE
The latecomer provision was developed to prevent free-riders with later interconnections from making use of the clustering upgrades. It would require interconnection customers that connect within 10 years of the cluster upgrade’s in-service date to share in the cost of the upgrades.
Planners estimate the combined clusters could accommodate about 1,900 MW of generation with a maximum of about 1,200 MW on either radial.
The northern cluster projects could accommodate up to 350 MW of additional generation without any new lines south of Pittsfield, assuming the Surowiec-South line remains at 1,600 MW. The maximum is limited by N-1 and N-1-1 violations on lines south from Orrington. Doing the project without the double circuit while increasing Surowiec-South to 2,200 MW would permit 675 MW in additional generation.
The clustering methodology received support from 95% of the Participants Committee in February.
Generators joining the study will be required to post a “very significant financial commitment” — the lesser of $1 million or 5% of the customer’s estimated costs for the upgrade, McBride said.
If either cluster is less than fully subscribed, the RTO will allow resources to withdraw to avoid a higher cost allocation.
“If the cluster doesn’t fill … we’re going to be continuing coming back to the PAC” for other solutions, including a potential HVDC project, said McBride.
The RTO also could open a second cluster window next year following the award of contracts in Massachusetts’ solicitation for 9.45 TWh a year of Class I renewables (wind, solar, hydro or energy storage). The winning projects are scheduled to be chosen by Jan. 25, with contracts completed and sent for state regulators’ review by April 25. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
McBride said ISO-NE doesn’t want to delay the first study window until after the solicitation because of the number of Maine wind generators ineligible for the cluster study whose interconnection costs might be affected by the cluster projects. “Their studies shouldn’t be held up any further,” he said.
Responding to protests by National Grid, energy shippers and local distribution companies in New England, FERC on Friday ordered a technical conference on Algonquin Gas Transmission’s proposal to change the terms of its no-notice services (RP17-808).
In June, Algonquin asked the commission to approve an update its no-notice services, last changed in 1993, to reflect its “current practices and operational requirements” and eliminate requirements the company said have become outdated with automation and faster forms of communication.
The changes would clarify that customers under Algonquin’s AFT-E and AFT-ES rate schedules seeking no-notice service must have nominated and scheduled an equal quantity of gas on a pipeline upstream of Algonquin for that day.
It also would specify that the right to change primary delivery points under AFT-E/ES only applies to temporary capacity releases.
On July 27, commission staff issued a delegated order accepting Algonquin’s filing but suspending the changes until Jan. 1, 2018, subject to refund and further commission order.
Janice K. Devers, Algonquin’s director of tariffs, told RTO Insider that “the commission’s directive to convene a technical conference was not a surprise. There is a probably a desire on their part to get clarification on the issues prior to the end of the suspension period on Jann. 1, 2018.”
| Spectra Energy
Energy shippers Direct Energy Business Marketing and Shell Energy North America claimed the revisions to rate schedules AFT- E and AFT-ES would unnecessarily limit the availability of no-notice service by implementing more restrictive eligibility criteria, undercutting the commission’s policy of providing shippers with greater scheduling flexibility.
National Grid asserted that Algonquin had failed to show that the proposed tariff changes are just and reasonable. The company also said that it relies on the right to call on reserved capacity on an intraday basis without needing to submit nominations prior to the start of the gas day. The company said that helps it meet shifting daily demand from its predominately low-load-factor residential and small commercial customers.
Sprague Operating Resources, which operates refined products and materials handling terminals, filed a letter in support of the protests.
In its Sept. 1 order, the commission said it lacked enough information to determine whether Algonquin’s proposed tariff changes are just and reasonable. The commission said that discussion at the conference would not be limited to the issues identified in the order.
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 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.
| IHS, Cedigaz, U.S. DOE
“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.
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.”
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 offer price 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.
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.
| 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.
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).
“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.)
| AEP
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.
