The IRS has issued additional guidance clarifying the qualification rules for facilities claiming the production tax credit (PTC) under the new “start construction” definition enacted earlier this year. Earlier guidance provided two methods to determine
when construction has begun on a facility: 1) actually starting physical work of a significant nature; or 2) when a taxpayer pays or incurs five percent or more of the total cost of the facility. In either case, the taxpayer must make continuous efforts to advance towards completion of the facility. The additional guidance clarifies those two qualification tests and describes how a facility can still qualify for the PTC if
the facility’s ownership changes hands. The guidance also clarifies that a “master contract,” which is defined as a “binding written contract for a specific number of components to be manufactured, constructed, or produced for the taxpayer by
another person under a binding written contract,” meets the safe harbor qualification test. The new PTC guidance is posted here.
On September 19, FERC issued Order No. 785, Final Rule on Generator Requirements at the Transmission Interface in Docket No. RM12-16-000, accepting a NERC proposal to revise four existing Reliability Standards to extend and/or clarify their applicability
to generator interconnection facilities. The modifications are designed to close a perceived reliability gap involving such facilities, and will go into effect 60 days after the rule is published in the Federal Register.
DOE Announces Fourth Authorization for LNG Exports to Non-FTA Nations. Does This Mean Full Steam Ahead?
On September 11, 2013, the United States Department of Energy (DOE) announced its approval of the fourth license application to export domestically produced liquefied natural gas (LNG) to countries with which the United States does not have a free trade agreement (FTA). Subject to an environmental review and final regulatory approval, DOE conditionally authorized Dominion Cove Point LNG, LP (Dominion) to export up to 0.77 billion cubic feet (bcf) of LNG per day for more than 20 years from the Cove Point LNG Terminal in Calvert County, Maryland. Cumulatively, DOE has now authorized a total export volume of
6.37 bcf/day. The first such authorization was granted on May 20, 2011, to Sabine Pass Liquefaction, LLC to export LNG from a terminal in Cameron Parish, Louisiana. DOE subsequently took a two-year intermission from reviewing non-FTA LNG export applications to further analyze a variety of global and domestic economic implications of such exports.
DOE granted the next non-FTA LNG export authorization on May 17, 2013, to the Freeport LNG Terminal in Texas, and on
August 7, 2013, conditionally authorized Lake Charles Exports, LLC to export LNG from a facility in Louisiana.
DOE approval is required for all exports of LNG under section 3 of the Natural Gas Act (NGA) (15 U.S.C. § 717b). Exports to non-FTA countries, such as Japan—currently the world’s largest LNG importer—are subject to a “public interest” test, and DOE may refuse to grant permission to export if it finds that the exports “will not be consistent with the public interest.” The “public interest” assessment, which generally takes into account, inter alia, the economic, energy security, and environmental impacts of granting LNG export authorizations, is time-consuming and has become an increasing concern for domestic producers and investors, as well as some business and political leaders.
As technological advances, particularly in the area of hydraulic fracturing (i.e., “fracking”), allow producers to extract greater quantities of natural gas at lower cost, there is mounting pressure within the US to take advantage of natural gas demand in overseas markets. DOE currently has nearly 20 export applications for a combined total of about 29 bcf/day pending in its review queue. Meanwhile, US politicians, policy analysts, and business leaders debate how much—if any—additional LNG exports DOE should authorize. This debate, fueled by long construction lead-times, other regulatory risks, high investment and transportation costs, domestic gas supply ramifications, and the dynamic global landscape of energy markets, highlights potentially significant obstacles in the unchartered waters of the LNG export industry.
One side of the debate focuses on current global LNG market conditions and advocates rapid expansion of the US LNG export industry to take advantage of existing economic opportunities. One such advocate is Senate Energy and Natural Resources (SENR) Committee Ranking Member Lisa Murkowski (R-AK), who released a white paper on August 6 titled “The Narrowing Window: America’s Opportunity to Join the Global Gas Trade.” The paper predicts that the US will have a natural gas production surplus by the end of this decade. Meanwhile, citing data from the International Energy Agency, the paper claims that the size of the global LNG trade will grow more than 75 percent by 2035. The US therefore has an “historic opportunity” to join the global gas trade. Sen. Murkowski warns, however, that the opportunity “will not be open indefinitely.” Rather, the window for US participation “is narrowing, and there is a real possibility that the
nation will miss out.” Based on “the latest analysis from academia, think tanks, the private sector, and government agencies,” the growing demand for LNG is “quickly being met by forthcoming supply” and locked into long-term contracts by world LNG export leaders, such as Qatar, Malaysia, Australia, and Nigeria, among others. Sen. Murkowski concludes her paper with several specific recommendations, including that the DOE, which “has already determined that exports of LNG are in the national interest,” should “move forward on all export applications in a timely manner” and should only consider revising its review procedure if it will “expedite, rather than delay, the process.” Additionally, “[t]he development of natural gas resources should be a priority” for the US and federal agencies with jurisdiction over natural gas matters should “collaborate to ensure there is no duplication of effort and that all policy goals are properly aligned.”
On the other end of the debate, some politicians and domestic industries are calling for caution in DOE’s consideration of additional export authorizations, arguing that impacts on domestic gas prices must be further studied. Following the DOE’s Dominion order, Sen. Ron Wyden (D-Ore.), SENR Committee Chairman, released the following statement:
“With today’s approval, the United States is now squarely in the range that experts are saying is the most likely level of US natural gas exports. If DOE approves exports above that range, the agency has an obligation to use most recent data about US natural gas demand and production and prove to American families and manufacturers that these exports will not have a significant impact on domestic prices, and in turn on energy security, growth and employment.”
Foreshadowing this reaction, earlier this year Sen. Wyden asked Assistant DOE Secretary Chris Smith in a SENR Committee hearing where the DOE “is going to draw the line” on the volume of LNG that will be authorized for export. Sen. Wyden presented a chart depicting the price disparity of natural gas between Asia
and the US, stating “it’s very understandable why North American natural gas producers would want to build LNG export terminals so they can sell natural gas to Asia at three or four times the price here. What’s less clear is how this is going to be beneficial for our consumers and our businesses that are going to have to compete with these prices,” concluding “[e]xports in the United States are going to make natural gas like the oil market.”
As Sen. Wyden indicated, the price of gas in the US is currently considerably lower than prices in other parts of the world. Although less than Asian markets, natural gas prices in Europe are still generally a little over double US prices. Experts disagree on whether there is a threshold at which US participation in this high-priced global LNG market will cause greater domestic harm than good and, if so, where that threshold lies.
One of the studies that the DOE commissioned after issuing its first export authorization order was a study by NERA Economic Consulting on the domestic impact of LNG exports in a range of scenarios, including exports in the amount of 6 bcf/day, 12 bcf/day, and unlimited exports. The study, released in December 2012
and backed by a subsequent study by ICF International for the American Petroleum Institute, concluded that the US’s “net economic benefits” from LNG exports—which are predicted to include the creation of up to 220,100 to 452,300 new US jobs over the next 20 years and the increase in US gross domestic product by US$15.6 to 73.6 billion/year from 2016 to 2035—will “increase as the level of LNG exports increase.” Many interpret this to mean that LNG exports should be unlimited.
Other studies have concluded that domestic prices of natural gas will intolerably rise as increasing volumes are exported offshore and the global natural gas market moves towards convergence. PIRA Energy Group released a report earlier this year analyzing the “undeniable reality” that “[d]omestic end-users and seasonal
storage injectors” will have to “compete with higher-priced foreign destinations” because the “fairly insular” state of gas markets and Henry Hub pricing in North America will be “immediately exposed to supply, demand, inventory, and pricing issues in other parts of the world.” Charles River Associates (CRA), for The Dow Chemical Company, compared the domestic economic contributions of LNG exports versus the economic contributions of the use of equivalent sums of natural gas in the US manufacturing industry. CRA’s
report concluded that the increase in domestic gas prices due to LNG exportation will negatively impact the critically important gas-intensive manufacturing industry in the US, and “the US economy is better off with natural gas used in manufacturing than natural gas exported as LNG.”
The outcome of these various analyses is contingent upon numerous assumptions, including the number of export facilities that attain commercial operation, sustained demand compared to available supply going forward, transportation availability and costs, and a kaleidoscope of other factors. DOE seems to recognize that it may be entering a new phase of this debate in its Dominion order, acknowledging that the cumulative export volume it has authorized now “moderately exceeds the 6 bcf/d volume evaluated by NERA in its ‘low’ export cases” and committing to “continue
to assess the cumulative impacts of each succeeding request for export authorization on the public interest with due regard to the effect on domestic natural gas supply and demand fundamentals.” Whether DOE heeds Sen. Murkowski’s call to take advantage of the narrowing window for US LNG exports or puts on the brakes in light of renewed calls for more data and impact studies remains to be seen.
FERC Addresses ISO-NE Capacity Supply Obligations, Walks a Fine Line Between Generator Cost Recovery and Maintaining Reliability
Jane E. Rueger
FERC issued an order last month interpreting the capacity
supply obligation (CSO) in ISO-NE that is notable in its attempt to preserve the reliability goals of the CSO while recognizing practical limits on market participants’ ability to make units available
in real time. However, the order presents some significant ambiguities for market participants going forward, and market participants should evaluate their market strategies to ensure compliance with FERC’s interpretation of the CSO under the ISO-NE tariff.
In its order, FERC granted in part and denied in part the New England Power Generators Association’s (NEPGA) complaint against ISO-NE alleging that ISO-NE inappropriately interpreted its tariff to impose a firm fuel obligation on all resources with a CSO. The order is a mixed bag for generators in ISO-NE, concluding that the ISO-NE tariff imposes a “strict performance obligation
on capacity resources” that precludes economic outages for such resources “including outages based on economic decisions not to procure fuel or transportation,” but also concluding that
“a demonstrated inability to obtain natural gas or transportation may legitimately affect whether a resource is physically available.”
The order starts from the premise that the CSO obligation is
a “strict performance obligation” and concludes that “a capacity resource that fails to comply with dispatch instructions when
it is physically available but has determined not to procure fuel or transportation due to economic considerations is in violation”
of the ISO-NE tariff. Nonetheless, the order further concludes that “a demonstrated inability to procure fuel or transportation for
a resource to run beyond (in terms of hours and/or incremental MWs) its day-ahead commitment, or when not scheduled in the day-ahead market, may legitimately affect whether a resource is physically available. If a capacity resource cannot procure fuel or transportation in real time in order to run at dispatch levels
beyond its day-ahead commitment (or when not scheduled in the day-ahead market), then the resource is not physically available to perform for a reason beyond the resource’s control for those additional hours and/or incremental MWs; thus the resource may be excused for nonperformance.” The reference to procurement “in real time” when the resource has not been committed in the day-ahead market is important; under this rubric, if a generator with a CSO is not committed in the day-ahead market, it is not
obligated to maintain firm fuel and transportation for its facility on the chance that ISO-NE might nonetheless dispatch it in real time. Instead, if dispatched in real time beyond its day-ahead commitment level, the generator must at that time procure
fuel and transportation necessary to meet dispatch absent a “demonstrated” inability to “procure fuel or transportation in real-time.”
Reading these conclusions in conjunction with one another, capacity resources risk a finding that they are in violation of the proposes to establish separate standards for utility boilers and Integrated Gasification Combined Cycle (IGCC) units, which primarily consume coal, and for natural gas-fired stationary combustion turbines. While modern natural gas-fired facilities are expected to be able to readily comply with the proposed NSPS, compliance with the proposed NSPS for coal-fired units presumes use of carbon capture and storage (CCS) as the best system of emission reduction (BSER) to comply. The proposal has already generated outcry from some corners of the electric and coal industries and, together with anticipated EPA limits on emissions ISO-NE tariff if they do not reserve gas supply and transportation of CO2 from existing fossil-fueled plants due out next year, revive service to support their day-ahead offers. That is, until such time as the capacity resource has learned that it was not committed in the day-ahead market, the capacity resource risks a tariff violation if it makes the economic decision not to procure gas and transportation in support of its day-ahead offer on the expectation that it would not be selected and then cannot supply fuel when actually committed.
The Commission recognizes that its interpretation will likely have adverse impacts on a capacity resource’s ability to recover costs associated with fulfilling its CSO given the current ISO-NE tariff provisions governing cost-recovery. FERC cross-referenced its order earlier in the summer directing ISO-NE to revise its tariff to permit resources to submit a Section 205 filing for cost-recovery, including fuel and variable O&M costs, in certain circumstances. By doing so, the order invites further filings regarding offer pricing and cost-recovery going forward. Moreover, FERC recognized that determining whether a generator has suffered a “demonstrated” inability to procure fuel or transportation is complicated and
fact-specific, and required that ISO-NE, through its IMM, file an informational filing containing a “non-exhaustive list of factors that the IMM will consider” when determining whether a generator has demonstrated an inability to procure fuel or is instead in violation of the ISO-NE tariff. This informational filing will also likely generate further comment at FERC and within the ISO-NE stakeholder process.
EPA Proposes Carbon Emission Standards for New Power Plants: First of a One-Two Punch for Coal?
Jane E. Rueger and Patrick Holten
On September 20, 2013, the Environmental Protection Agency (EPA) issued a significantly revised proposal for a new source performance standard (NSPS) to limit emissions of carbon dioxide (CO2) from new fossil fuel-fired generating facilities. Unlike its predecessor proposal issued last year, the 463-page proposed rule, which was issued at the direction of President Obama as part of his multifaceted regulatory plan to address global climate change, concerns over the viability of coal going forward and the changing generation fuel mix in the United States.
Under the proposed regulations, the annual emission limit for natural gas-fired sources would be 1,000 lb CO2 /MWh for larger units, i.e., those generating more than 850 MMBtu/hr. A 1,100 lb CO2 /MWh limit would be set for some smaller units generating less than 850 MMBtu/hr. These standards of performance for natural gas-fired turbines are based on modern, efficient natural gas combined cycle (NGCC) technology as the BSER.
More controversially, the annual emission limit for coal-fired facilities would be 1,100 lb CO2 /MWh. A lower 1,000 to 1,050 lb. CO2 /MWh limit over a longer, seven-year term would also be allowed. In either case, the targets are based on the presumptive use of carbon capture and storage (CCS) as the BSER to comply. This proposal generated an immediate outcry, with some proponents of coal arguing that CCS technologies remain commercially unproven and prohibitively expensive. Sen. Joe Manchin (D-W.Va.) issued a statement the same day the proposed new rules were issued, denouncing the proposal as forcing “
an industry to do something that is technologically impossible…. If these regulations go into effect, American jobs will be lost, electricity prices will soar, and economic uncertainty will grow.”
Interestingly, the EPA expects these new rules to “result in negligible CO2 emission changes, quantified benefits, and costs by 2022” based on economic models by the Energy Information Administration and market trends that EPA says indicate “few, if any new coal-fired power plants” are likely to be built in the next 12 years. In addition, the EPA says the economic bias is firmly in favor of electricity generators with new technologies that are predesigned to meet these rules, primarily via natural gas combined cycle generators. Nonetheless, the EPA insists that the Clean Air Act requires it to act on carbon as a greenhouse gas pollutant, and therefore it must issue the rules. Contrary to its detractors, EPA argues that the proposed rules will provide economic and regulatory certainty.
Equally if not more important, the proposed rules set the stage for new emission control rules for modified, reconstructed and existing plants, which the President has directed the EPA to propose by June 1, 2014, with final standards issued no later than June 1, 2015. The last two years have already seen a record number of announced retirements of coal-fired units, particularly in the Midwest. The combined effect of the proposed NSPS for new coal-fired plants and the anticipated NSPS for existing
coal-fired plants may exacerbate the trend away from coal-fired generation, threatening to reduce the diversity of generation fuel mix in the United States and causing a greater reliance on natural gas-fired and renewable units.
Once the rules for new power plants are officially published in the Federal Register, a 60-day comment period will begin with an 11-hour public hearing also to be scheduled. More information on this issue, including the text of the newly proposed regulations, is posted here.
CRS Report Spotlights PTC and Other Expiring Energy Tax Incentives
A report issued in early September by the Congressional Research Service (CRS) focuses on the temporary nature of numerous energy tax policy provisions and serves as a reminder that many key energy tax provisions face imminent expiration.
As noted by CRS, the Production Tax Credit (PTC) for renewable energy is scheduled to expire for all projects on January 1, 2014. Unless Congress acts, only those projects that have begun construction (see also Energy Highlights on page one) before that date will qualify. At a projected ten-year cost of US$12.2 billion, the PTC has the largest budget impact by far among the list of expiring energy provisions. The second costliest (in terms of foregone tax revenue) energy tax provision expiring at the end of the year is the credit for non-business energy property. The ten-year budget impact of this provision is just US$2.4 billion, according to CRS.
The CRS report notes that the expiration of these provisions “means energy tax policy will likely be considered in the current Congress.” However, CRS does not say that action is certain this year, i.e., in advance of the year-end expirations. In the past, Congress has retroactively extended a number of expired provisions, and next year, a similar after-the-fact extension
of the PTC could occur.
The CRS report also explains that the President’s FY 2014 budget not only proposes making the PTC permanent, but also expanding it. The proposal from the President would make solar projects qualify and make the PTC refundable for projects that start construction after 2013. As currently construed, the PTC’s base amount is 1.5 cents (indexed annually for inflation) per kilowatt hour of electricity produced. The amount of the credit is 2.2 cents per kilowatt-hour for ten years after the qualified facility is placed in service.
Two possible avenues for legislative action on these and other temporary energy tax provisions appear likely, according to CRS. First, Congress may act to extend these provisions as part of a legislative package of so-called tax extenders, either before or retroactively after the dates of expiration. CRS also notes that
a broader effort under way in the House and Senate tax-writing committees to comprehensively reform the tax code has included a more deliberative examination of the efficacy and cost of these and other temporary tax provisions. “A base-broadening approach to tax reform might consider the elimination of various energy tax expenditures in conjunction with a reduction in overall tax rates,” the CRS report states.
CRS is the non-partisan research arm of Congress. Its reports are released only to Members of Congress and their staff, though as a practical matter, they are routinely circulated and made public soon after being issued. The reports are especially informative for lawmakers who serve on committees outside of the policy area discussed in each report.