The Federal Energy Regulatory Commission has ordered NYISO to begin a stakeholder proceeding to resolve a dispute over the installed capacity market on Long Island, which was excluded from a previous attempt to address transmission congestion in the areas around New York City.
The ISO is to report its findings to FERC by June 1, 2015. FERC rejected a recommendation by the ISO’s Market Monitor that it complete tariff changes to address the issue by June.
In August 2013, FERC approved NYISO’s proposal to create a new capacity region encompassing New York City and its northern suburbs. The zone did not include the Long Island suburbs because NYISO said insufficient transmission existed there for it to participate.
Critics said Long Island (Zone K) contributes to overloading of the Upstate New York/Southeastern New York (UPNY/SENY) Interface — which led to the creation of the new capacity region — but has escaped any cost responsibility for the overloads, thus causing higher capacity prices for New York and the Hudson Valley (Zones G, H, I and J), which were included.
FERC’s order follows a February 2014 technical conference that considered whether Long Island could be modeled as an export-constrained zone for future ICAP Demand Curve proceedings.
“We agree that it would be worthwhile for NYISO and its stakeholders to explore whether a proposal can be developed that could reduce the cost of procuring capacity while meeting the NYISO [loss-of-load expectation] objective,” FERC said (AD14-6).
FERC directed the report to include points raised by the Market Monitor, which said that the ISO should be required to improve its methodology for modeling deliverability constraints and calculating local capacity requirements.
The new capacity region went into effect in May over the strenuous objections of utilities, consumer groups and the New York Public Service Commission. NYISO said it was necessary to send price signals to encourage development of additional generation and transmission in the area.
FERC agreed with NYISO that June was too soon to require tariff amendments but added “market rule changes that could reduce costs should not be unduly delayed.”
PJM’s most recent competitive window for transmission projects attracted 63 proposals from 12 entities, the majority of them transmission owner upgrades.
The second window in the 2014 Regional Transmission Expansion Plan was open to proposals addressing transmission owner criteria, 2019 baseline n-1 voltage, 2019 n-1-1 voltage and 2018 light load reliability criteria problems. The proposals address about 49 facilities with thermal violations and 69 with voltage problems in nine TO zones.
Of the 63 proposals, 43 were transmission owner upgrades (ranging in cost from $200,000 to $71 million) and 20 are greenfield projects ($6.1 million to $450 million).
The window, the result of the Federal Energy Regulatory Commission’s Order 1000, was open from Oct. 17 through Nov. 17, although PJM extended the deadline for proposals regarding violations in one area to Dec. 5.
Industrial customers, consumer advocates and state regulators called on the Federal Energy Regulatory Commission to reject a request by MISO transmission owners for a 50-basis-point adder as an incentive for their participation in the RTO.
The Nov. 6 filing by MISO and its transmission owners (ER15-358) came weeks after the commission ordered an evidentiary hearing on complaints from industrial customers that the base rate of return of MISO’s 24 transmission operators is not just and reasonable (EL14-12). (See FERC Orders ROE Hearing on MISO TOs.)
FERC made return on equity (ROE) adders available to RTO members in Order 679, a response to a Congressional mandate in the 2005 Energy Policy Act. “Subsequent commission orders have made clear that this incentive for RTO participation remains available both to new and continuing RTO members,” the TOs said.
In filings last week and in late November, opponents said that many TOs have been members of MISO for more than a decade and there’s no threat that they would leave if they couldn’t collect the adder.
“Instead, at a time when base ROEs must decrease to remain consistent with prevailing conditions in capital markets, the MISO TOs are simply using the RTO adder as a means for attempting to claw back some of that revenue,” industrial consumers from Illinois, Indiana, Minnesota and Wisconsin said in a Nov. 28 filing.
They contend that electric customers would pay about $50 million annually toward the adder without any corresponding benefits. “The MISO TOs have not demonstrated whether an additional $50 million in revenue each year plays a pivotal role in their economic analysis of MISO membership.”
The Organization of MISO States also filed a protest to the proposed adder, saying it “appears intended to mitigate against any refunds that may result” from the pending ROE reduction case.
OMS said the adder should be awarded only when it influences decisions to join or remain in an RTO. “The historical record has simply shown there are no instances of MISO members leaving its membership except to transfer to a different RTO,” OMS said.
OMS asked the commission to consolidate the adder filing with docket EL14-12, contending “that the TOs’ waiver and deferral requests clearly demonstrate the linkage between the RTO adder and the level of the base ROE and the zone of reasonableness.” A settlement conference in the ROE case is set for Dec. 16.
A number of other groups also have asked FERC to deny the adder, including Hoosier Energy Rural Electric Cooperative, Southern Illinois Power Cooperative and Dairyland Power Cooperative. They contend that the TOs included no rate of return analysis as part of the adder request.
FERC opened the door to ROE fights in June, when it changed the way it sets ROE rates for electric utilities to a two-step discounted cash flow methodology similar to what it uses for natural gas and oil pipelines. (See FERC Splits over ROE.)
ISO-NE generators asked federal regulators to change market rules ahead of February’s capacity auction while state officials complained consumers face excessive costs because of unrealistic load forecasts. In all, the ISO’s load and supply interests opened three capacity market dockets at the Federal Energy Regulatory Commission in the last two weeks. (See related story, ISO-NE Stakeholders Challenge Capacity Rules Ahead of Auction.)
By William Opalka
New England consumers could purchase hundreds of millions in excess capacity in the upcoming auction because ISO-NE has underestimated the impact of distributed generation and its pay-for-performance (PFP) program, state officials told FERC.
The New England States Committee on Electricity made the allegation in a challenge to ISO-NE’s Nov. 4 filing on its installed capacity requirement (ICR), local sourcing requirements and Hydro-Quebec interconnection capability credits (HQICC) for the 2018/19 delivery year (ER15-325).
The New England Power Pool Participants Committee also criticized the ISO’s failure to incorporate the distributed generation (DG) forecast in its ICR value.
The ISO proposed an ICR value of 35,142 MW, which includes 1,970 MW of emergency generation assumed obtainable from New Brunswick, New York and Quebec. The net amount of capacity to be purchased, after deducting the HQICC value of 953 MW per month, is 34,189 MW, the ISO said.
NESCOE said it does not dispute ISO-NE’s adherence to the market rules and methodologies in calculating the ICR to be used for the ninth Forward Capacity Auction (FCA). “However, NESCOE expects that assumptions used in setting the ICR for future years — beginning with FCA 10 — will incorporate contributions to resource adequacy from incremental ratepayer investments in renewable DG resources and investments in improved performance,” it said.
ISO-NE’s DG forecast completed earlier this year projects that solar DG resources will increase in New England from roughly 175 MW in 2013 to 489 MW in 2018 and 632 MW by 2023.
“ISO-NE’s calculation of the ICR used for FCA 9 wholly disregards the very forecast it developed, ignoring hundreds of megawatts of solar resources required by state policies, which ISO-NE itself tracked and verified will come online over the next three years,” NESCOE said. “In addition, while one of the purported benefits of ISO-NE’s proposed PFP program was to ensure better resource performance, the ICR value for the first year under the PFP construct, the 2018-2019 Capacity Commitment Period, fails to reflect any projected increase in resource availability resulting from this new market design.
“Consumers should not pay to strengthen financial incentives under PFP and then be forced to purchase more resources than are needed to achieve resource adequacy standards as if these strengthened incentives were not in place.”
In its 2014 Regional System Plan, ISO-NE cited uncertain market rules as an impediment to using the forecast in resource adequacy studies for the ICR, including treatment of pay-for-performance. It says it is awaiting guidance from FERC “before being able to determine the best methods for potentially incorporating the DG forecast into the resource adequacy process.”
The U.S. Supreme Court has agreed to hear a challenge of the Environmental Protection Agency’s mercury emissions cap that alleges the emissions limits will impose huge costs on local economies.
Industry trade groups and almost two dozen states told the court that the Clean Air Act requires the EPA to consider compliance costs at an earlier stage in the regulatory process. “EPA’s decision to ignore entirely the costs of its decision has led to one of the most far-reaching and costly rules — if not the most costly rule — ever imposed” under the Clean Air Act, the Utility Air Regulatory Group wrote in its appeal.
Environmental groups are closely watching the case. “Mercury and other air toxins from coal-fired power plants are a threat to public health, and all Americans must be protected from them,” said Vickie Patton, general counsel for Environmental Defense Fund. The group has filed an amicus brief in defense of the Obama administration. The court has not set a date for oral arguments.
House Extends Wind Production Tax Credit Until End of 2014
The House passed legislation that extended wind production tax credits, along with other renewable incentives, until the end of 2014, retroactively extending those credits from when they expired at the end of last year.
The $42 billion bill, passed by a vote of 378-46, extends nearly $10 billion in energy tax credits. Although it’s good news for wind and other renewable-energy advocates, wind energy and environmental advocates say it is short-sighted and that a multi-year credit is needed to support the growing industry.
“The three-week extension being considered by the House does not provide the certainty and stability needed to keep U.S. factories open and keep workers on the job,” Tom Kiernan, chief executive officer of the American Wind Energy Association, said in a statement. Since the credit expired last year, new wind installations have dropped 92% compared to 2012. Fossil fuel groups such as the American Energy Association have fought the extension, saying it gives wind energy an unfair economic advantage.
FERC Approves 5th Settlement with NERC, CAISO in 2011 Blackout
The Federal Energy Regulatory Commission approved the fifth settlement related to the 2011 Southwest Blackout that left 5 million people in California, Arizona and Mexico in the dark for 12 hours.
The settlement between the commission, the North American Electric Reliability Corp. and CAISO includes a $6 million civil penalty against CAISO that ends the investigation. FERC and NERC concluded that CAISO had failed to appropriately monitor the transmission system in Southern California, contributing to the tripping of the San Onofre nuclear plant and a blackout of the San Diego and Baja California areas. According to terms of the settlement, $2 million of the fine will be split between NERC and the U.S. Treasury, and the remaining $4 million will be invested in reliability improvements.
Settlements have already been reached between FERC and four other parties linked to the 2011 blackout: the Western Area Power Administration’s Desert Southwest Region, Southern California Edison, Arizona Public Service Co. and the Imperial Irrigation District.
Constitution Pipeline Gains FERC OK to Take Gas to New England
The Federal Energy Regulatory Commission approved a pipeline that will deliver natural gas from the Marcellus Shale fields to New England. Construction could start as soon as next quarter.
The Constitution Pipeline will run 124 miles from an existing pipeline in northeast Pennsylvania to New York, connecting with lines into New England. Once in operation, it will ease gas transportation constraints into those regions. Those constraints led to gas and electricity price spikes last winter. The pipeline will be owned by Williams Partners, Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings.
NM Fines DOE $54M for Nuclear Material Storage Violations
New Mexico fined the U.S. Department of Energy $54 million for more than 30 violations of state regulations that caused the contamination of workers and indefinite closure of the nation’s only underground nuclear waste repository.
The violations at the Waste Isolation Pilot Plant and the Los Alamos National Laboratory caused the rupture of a canister of nuclear waste at the pilot plant in February, which contaminated 20 employees and forced the facility to shut down. The state accuses Los Alamos of mixing incompatible waste, treating hazardous waste without a permit and failing to notify regulators about changes in the way waste was being handled.
“DOE now has an opportunity to learn from these mistakes and implement meaningful corrective actions that will ensure the long-term viability of the Los Alamos National Laboratory,” Ryan Flynn, New Mexico’s environment secretary, said in a letter to the lab.
Martha’s Vineyard Wind Energy Leases up for Auction Jan. 29
More than 1,160 square miles of open water off Martha’s Vineyard and Nantucket will be auctioned to commercial wind energy developers on Jan. 29.
The tract – larger than the state of Rhode Island – will be the largest off-shore wind energy tract in the U.S. Twelve companies, including Fishermen’s Energy, which was recently rebuffed from developing a wind energy project off the coast of New Jersey, are qualified to bid for the four leases.
Offshore Fracking in California May Spur Lawsuit Alleging Violations
An environmental group has threatened to sue the federal government to halt the use of hydraulic fracturing techniques in California offshore oil drilling.
The Center for Biological Diversity filed a notice of intent to sue the U.S. Interior Department over fracking, which it says violates federal law. The center said oil companies have used fracking at least 21 times without performing an analysis of the effect on coastal communities and wildlife. The center said it will file suit if federal authorities don’t step in to stop it within 60 days.
“The federal government’s turning a blind eye as offshore fracking threatens to poison our beautiful beaches and coastal waters,” said Miyoko Sakashita, an attorney and director of the group’s oceans program. “We need offshore fracking stopped immediately before chemical contamination or an oil spill devastates California’s coastal communities and kills sea otters and other endangered marine wildlife.”
Sen. Barbara Boxer (D-Calif.) accused the Nuclear Regulatory Commission of ignoring vital safety recommendations made after Japan’s Fukushima Daiichi disaster.
“The reality is that not a single one of the 12 key safety recommendations by the Fukushima Near-Term Task Force has been implemented,” Boxer said at a hearing of the Environment and Public Works Committee, which she chairs.
All five NRC commissioners attended the Senate hearing, and they defended the nuclear agency’s response to the 2011 disaster in Japan. “The NRC continues to make significant progress in implementing post-Fukushima safety enhancements,” NRC Chairwoman Allison MacFarlane said. She added that U.S. nuclear stations are already working on more crucial improvements, including reinforcing spent fuel pools, bolstering backup generation and bringing in more emergency equipment.
“As a result of these activities, nuclear power plants in the United States will have more defense and depth to cope with long losses of offsite power and other severe accident conditions,” MacFarlane said.
Connecticut Light & Power’s proposed distribution rate increase was cut by 41% by the state’s Public Utilities Regulatory Authority in a draft decision.
The utility asked for $221 million in additional revenue with a 10.2% return on equity (ROE). The draft ruling would allow recovery of $130.1 million, including some previously approved costs from major storms in 2011 and 2012. The ROE was cut to 9.17%. The base ROE was further cut to 9.02% for one year as a penalty for the utility’s performance in preparation and service restoration from Tropical Storm Irene in 2011 and an October 2011 snowstorm.
CL&P also proposed increasing the monthly service charge that most residential customers must pay regardless of consumption to $25.50 from the current $16. The draft decision allows the fixed rate to increase to $19.50 monthly.
An average residential customer using 700 kWh of electricity would see an increase of approximately $7.12 per month. PURA said the increases will be sufficient to allow CL&P to fund capital improvements to upgrade its distribution system.
A final vote by PURA’s commissioners is scheduled for Dec. 17.
NextEra Energy, parent company of Florida Power & Light, announced plans to buy Hawaiian Electric for $2.63 billion, taking over a utility that is losing significant load to renewable competition.
NextEra, already North America’s largest generator of wind and solar electricity, was interested in Hawaiian Electric because of the utility’s ambitious plans to wean itself from fossil fuels. Hawaiian Electric has said it plans to get 65% of its power from renewable sources by 2030.
“It makes a lot of sense for NextEra with all the renewables that Hawaiian Electric was going to do,” Tim Winter, an analyst at Gabelli & Co. in Rye, N.Y., told Bloomberg News. NextEra is “the premier renewable energy builder and developer and really good at transmission.”
Wisconsin Public Service Corp. to Build 400-MW Plant near Kaukauna
Green Bay-based utility Wisconsin Public Service Corp. plans to build a 400-MW natural gas-fired plant at its Fox Energy Center.
In filings with the state Public Service Commission, WPSC said the new generation could offset contemplated retirements of coal-fired plants. The $500 million project would get underway in the spring of 2016 and be operational by 2019.
The Fox Energy Center in Kaukauna is home to two plants, generating 600 MW. WPSC is a subsidiary of Integrys, which is being acquired by WE Energies of Milwaukee in a $9.1 billion deal.
Ameren’s Callaway Plant Offline After Reactor Trips Because of Unknown Issue
Ameren Missouri’s 1,200-MW Callaway nuclear generating plant shut down last week after an electrical problem caused its reactor to trip, forcing the utility to use other plants to make up for what amounts to about 20% of its electricity supply. The Nuclear Regulatory Commission, after a preliminary investigation, classified the incident as a nonemergency and said no radiation was released.
The reactor trip came not long after crews finished refueling the reactor and installing a new reactor vessel pressure head, but company officials said the outage was unrelated to those jobs. They did not say when the plant will be restarted.
Ameren Welcomes its First Solar Facility in its 100-Year History
Ameren Missouri, which has been in business for more than a century, launched its first solar energy facility last week.
The 6-MW O’Fallon Renewable Energy Center is the first solar facility in Ameren’s mix, company officials said. A second plant is to be built in 2016.
“We are moving away more from carbon-based energy and this solar plant is one of the strategies Ameren Missouri is executing on,” said Scott Wibbenmeyer, the company’s manager of renewable development.
Xcel Denies it Owes Babcock & Wilcox $45M for Steam Generator Work
Xcel Energy, answering an allegation from Babcock & Wilcox Nuclear Energy that it owes the contractor $45 million for work done at the Prairie Island Nuclear Power Plant in Red Wing, Minn., said they both share responsibility for the project’s cost overruns and delays.
B&W “continued to lose ground against the schedule on a virtually daily basis,” Xcel said in court filings. In fact, Xcel said, the contractor owes it $3 million.
B&W said the increased costs of the job came about in part because Xcel changed the scope of the work. The work at the plant took more than a year.
PSE&G, Pilgrim Still Negotiating over Right-of-Way for Pipeline
Officials of Pilgrim Pipeline Holdings and Public Service Electric & Gas say they are still in negotiations over access to the utility’s land in New Jersey for use of a controversial pipeline, despite news reports that PSE&G had denied Pilgrim access.
The state chapter of the Sierra Club, which is opposed to Pilgrim’s plan for the pipeline, posted a news release on its website that said Pilgrim “was denied access to PSE&G right-of-way by the PSE&G Corporate Lands Division and now senior leadership has upheld that decision.” But Pilgrim official George Bochis said the companies are still talking. “It is early in the process and we continue to have discussions with PSE&G,” he said.
The 178-mile pipeline would transport crude oil from a rail terminal in Albany, N.Y., to a refinery in Linden, N.J. It would then carry refined products from Linden northward.
Dominion’s Millstone Nuclear Plant to Stay Non-Union After Vote
Workers at Dominion Resources’ Millstone Power Station in Waterford, Conn., last week rejected a measure to join the International Brotherhood of Electrical Workers. The vote was 183 for unionization to 222 against.
IBEW officials claimed that Dominion allowed some employees to take part in the election who shouldn’t have been eligible, including supervisors. “The company spent a tremendous amount of money to get the results to go their way,” said John Fernandes, business manager for IBEW Local 457.
A Millstone spokesman said the company was pleased with the results.
ISO-NE generators asked federal regulators to change market rules ahead of February’s capacity auction while state officials complained consumers face excessive costs because of unrealistic load forecasts. In all, the ISO’s load and supply interests opened three capacity market dockets at the Federal Energy Regulatory Commission in the last two weeks. (See related story, States, NEPOOL: ISO-NE Overestimating Capacity Needs.)
By William Opalka
Exelon, Calpine: ISO-NE New Entry Rule Suppresses Prices
Exelon and Calpine want FERC to change a pricing rule in the forward capacity market (FCM) in New England that FERC has previously rejected in PJM.
The companies are seeking a ruling by Jan. 23, before ISO-NE’s Forward Capacity Auction (FCA) for the 2018/19 capacity commitment period begins Feb. 2.
The New Entry Pricing Rule in the ISO-NE Tariff gives the sponsor of a new resource the option of locking in the price at which the resource first clears in an FCA for up to six subsequent delivery years.
In a complaint filed Nov. 28 (EL15-23), the companies said the rule suppresses prices for other capacity providers because it results in new resources entering the equivalent of zero-price offers in the six additional years.
FERC had rejected a similar rule in PJM but noted that PJM uses a downward-sloped demand curve in its capacity market.
“That distinction is no longer valid as ISO-NE has adopted a downward-sloping demand curve beginning with the FCA for the 2018/2019 capacity commitment period,” the companies said. “As a result, the PJM precedent is now indisputably applicable to ISO-NE’s FCM rules.”
They said they are not trying to eliminate the rule but asked the commission to “remedy the impacts of the resulting price suppression.” Such a remedy could “entail additional payments” to other capacity suppliers, they said.
The New Entry Pricing Rule was intended to provide predictable revenues for new capacity. Earlier this year, the maximum lock-in period was extended from five to seven years, which FERC had acknowledged could result in lower market clearing prices.
The companies supported their complaint with an affidavit from Michael M. Schnitzer, a director of the NorthBridge Group, who said the zero-price offer requirement will significantly suppress FCM clearing prices, hurting both existing resources and new ones.
“Remedying this price suppression is even more vital in this case than it was in PJM’s case, because locked-in pricing is more widely available and the potential lock-in period is more than twice as long under ISO-NE’s New Entry Pricing Rule than under PJM’s [New Entry Price Adjustment] mechanism,” the companies added.
New England Gens: Cut Rebate Payments
Meanwhile, the New England Power Generators Association wants ISO-NE to immediately roll back the Peak Energy Rent Adjustment, saying recent policy changes eliminate the need for it and that its existence threatens reliability.
The group representing the owners of 26,000 MW of generation in New England filed a complaint (EL15-25) with FERC on Dec. 3. They seek to have ISO-NE modify the PER for Capacity Commitment Periods 5 through 8 — from now until early 2018 — and then eliminate it altogether for FCA 9. The auction covers delivery year 2018/19, when the ISO will implement its pay-for-performance program, which will tie capacity revenues to real-time performance.
“The current PER Adjustment, which obligates capacity suppliers to rebate a portion of their capacity revenues based on real-time energy prices, is unjust and unreasonable in light of the increases in the Reserve Constraint Penalty Factors (RCPFs) in ISO-NE’s energy market directed by the commission earlier this year,” the association said.
NEPGA requests a refund-effective date of Dec. 3, the effective date of the previously accepted increase in the RCPFs.
The new RCPFs could substantially increase real-time energy prices and, by extension, the PER Adjustment.
NEPGA says the PER Strike Price, which determines the magnitude of the PER Adjustment, should be increased by $250/MWh, as proposed recently by ISO-NE in its stakeholder process in response to the change in RCPFs.
The proposal fell short of the 60% support ISO-NE said it would require to seek FERC approval. The proposal won almost 58% support at the Markets Committee and a 47% vote in favor at the New England Power Pool Participants Committee.
The PER Adjustment was designed in part to discourage the exercise of market power through withholding and to provide a hedge to load against high real-time prices. NEPGA says any benefits now are outweighed by its likely cost.
The Federal Energy Regulatory Commission approved a revised joint operating agreement (JOA) between PJM and Duke Energy Progress (DEP) last week despite protests from the RTO’s Independent Market Monitor that it gives Duke favored treatment on interchange pricing.
The revisions to the JOA, which PJM originally signed with Progress Energy Carolinas (PEC) in 2005, were relatively minor, including updates to the company’s name and contact information to reflect Duke Energy’s 2012 acquisition of the utility.
The Market Monitor filed a protest in October contending that PJM should terminate the JOA and negotiate a new one to reflect the joint dispatch agreement (JDA) that PEC and Duke Energy Carolinas signed as part of the acquisition. (See IMM Calls for New PJM-Duke Progress JOA.)
FERC dismissed (ER15-29) the Monitor’s protest, saying that it was challenging unchanged portions of the agreement, not the changes themselves, making the protest beyond the scope of the filing. The commission said the Monitor could file a complaint in a new docket making its case that the dispatch agreement renders the JOA unjust and unreasonable.
In joint comments filed last month, PJM and DEP called the Monitor’s protest “a pretext to rehash old arguments on which the commission has already ruled.”
“Having failed to obtain its desired result in 2010 [when FERC approved the JOA], the PJM IMM now tries for a second bite at the apple,” they said.
Electric demand, industrial use and liquefied natural gas exports will make the Southeast the top destination for natural gas in the U.S. by 2019, according to a Bentek Energy study for America’s Natural Gas Alliance (ANGA).
Richard Smead, managing director of RBN Energy, presented the study results at a meeting of MISO’s Entergy Regional State Committee in Austin, Texas, last week.
Demand in the 10-state Southeast region will increase by 9.5 Bcf/d by 2024, about 39% of the projected demand growth in the U.S.
Gas burned to produce power will increase by 2.2 Bcf/d in the region, a 31% jump, with triple-digit increases in Tennessee (+290%), Kentucky (+276%) Arkansas (+150%).
“The rate of growth in power generation has been huge. A lot of that is driven of course by coal retirements … which raises the question of whether gas is capable of doing this,” Smead said. The answer, he said, is yes.
The study concludes that there is enough supply and pipeline capacity to meet any plausible power generation demand scenario in the Southeast “with stable, affordable power,” Smead said.
LNG Exports
Combined with LNG exports and increased industrial demand, the Southeast will become the nation’s top demand region by 2019, surpassing the Northeast. LNG exports will be responsible for more than half of the Southeast’s demand growth, with LNG shipments from three terminals in the Gulf and one in Georgia projected to hit 5.7 Bcf/d by 2021.
The Northeast is projected for a 3.4 Bcf/d increase in demand by 2024, less than a quarter of its projected 15.1 Bcf/d increase in production.
The Southeast’s demand growth will exceed its projected 3.1 Bcf/d increase in production, but its existing pipeline infrastructure — originally built to carry gas from the Gulf of Mexico to other regions — and pipeline projects capable of carrying 13 Bcf/d should be able to handle the imports. The region currently imports more than 5 Bcf/d.
There are 200 major industrial projects proposed for the Southeast, including a methanol plant envisioned for Louisiana. That guarantees that the pipelines will get built, Smead said. “It’s not being left to the [electric] utilities to pay for it all.”
Break-Even Prices Down
Meanwhile, producer break-even prices have fallen below the levels assumed in the Bentek study, which projects North American production growth of 26 Bcf/d by 2024.
“We’re running into studies now that are indicating between big increases in efficiency and the gas coming forward with oil production … that producer break-even prices are really closer to $2.50 to $3 [per MMBtu], meaning production growth just keeps on going,” Smead said.
The Federal Energy Regulatory Commission has ordered NYISO to begin a stakeholder proceeding to resolve a dispute over the installed capacity market on Long Island, which was excluded from a previous attempt to address transmission congestion in the areas around New York City.
