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.
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.
| EIA
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.
| EIA
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.
| FERC
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
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.
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.)
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.
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.)
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.”
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.
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.”
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).
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.
