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Key Takeaways | Tax Credit Bonuses for Low-Income and Coal, Oil and Gas Energy Communities

On September 13, McDermott Partners Heather Cooper and Philip Tingle provided a detailed overview of the bonus tax credits under the Inflation Reduction Act of 2022 for projects satisfying low-income thresholds or built-in energy communities with ties to coal, oil and natural gas, including the technical requirements for each bonus and how these new rules will impact deal pipeline, planning and negotiations.

Below are key takeaways from the discussion:

1. There is an annual capacity limitation of 1.8 gigawatts direct current for low-income bonuses. It’s unknown whether this capacity will be allocated to projects on a first-come, first-served basis or shared amongst all applicants annually in the event capacity is reached. The Internal Revenue Service must provide guidance on this point within 180 days of enactment.

2. Projects that fail to satisfy relevant low-income/poverty metrics are subject to recapture (with a one-time opportunity to cure). It remains to be seen whether circumstances outside taxpayer control (e.g., local economic improvement) will trigger recapture.

3. At present, it is difficult to transact on the energy community bonus-based projects located in brownfield or MSA/non-MSA because of a lack of guidance. Projects located in census tracts with retired coal fired EGUs or coal mines, however, can be transacted based on the statute alone.

4. Projects will require researching, tracking and targeting areas where coal mines closed, coal fired EGUs retired and (after relevant guidance is released) brownfields are located.

To access past webinars in the Navigating the New Energy Landscape series and to begin receiving Energy updates, including invitations to the webinar series, please click here.




Does the ADP in Your LNG SPA Meet Your Needs?

It’s that time of year again when the sellers and buyers of many of the world’s long-term liquefied natural gas (LNG) sales and purchase agreements (SPAs) must agree on the Annual Delivery Programme (ADP). In past years, this has typically been a mildly contentious process where both parties’ operations teams discuss, haggle and settle on an LNG delivery programme that roughly meets both parties’ needs. The discussions are framed by the terms of the applicable SPA but guided by cooperation and the goodwill generally found in long-term buyer-seller LNG relationships. Lawyers tend not to be involved. However, this is not the case this year.

With a global gas/LNG shortage and spot prices reaching record highs, there is a huge discrepancy between long-term LNG and spot LNG prices. At the time of drafting this article, Platts JKM is quoted at US$ 33.85 / MMBtu and Title Transfer Facility (TTF) is quoted at US$ 32.15/ MMBtu for January 2022 delivery. However, a long-term LNG SPA at a relatively good LNG price of 13.5% Brent would be at US$11.34/MMBtu with Brent at US$ 84/ bbl. An approximate US$ 20 / MMBtu difference or, for a mid-range LNG cargo size of 3,800,000 MMBtu, a US$76 million difference per cargo.

With this level of price difference, every cargo is vital. For sellers, any cargo that can be delivered spot rather than under a term SPA can provide significantly greater profits, and the converse is true for buyers. Many LNG buyers have recently adopted a strategy of buying a significant proportion of their LNG demand on a term basis but with spot purchases covering demand growth and swing. For these buyers, ensuring as many of their (currently lower priced) term cargoes arrive during the high demand, high cost winter months with lower price summer spot purchases making up any annual demand shortfall can significantly reduce their weighted average LNG purchase price.

The early long-term SPAs were developed for a point-to-point trade, often with a fleet of ships sailing continuously between a loading terminal and one or two particular receiving terminals serving a single SPA. Discussions on an ADP were relatively simple with both parties strongly incentivised to align delivery windows to reduce shipping and demurrage costs and ensure sufficient LNG supplies. But if the parties could not agree on a delivery programme, typically the seller had the final say.

However, the LNG industry has changed significantly since those early days, particularly with the advent of portfolio traders, diversion clauses (with or without profit sharing elements), upward and downward quantity tolerance and, most importantly, the spot market: all driving a more flexible, efficient and commercial LNG market. As the LNG market has developed, so has the drafting of the ADP provisions, with buyers increasingly wanting to set firmer delivery windows and have stronger rights for Upward Quantity Tolerance (UQT), Make-up and Make-Good cargoes.

So how does the gulf between spot and term prices and the development of LNG SPAs impact the ongoing ADP discussions? Instead of coordinated [...]

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FERC Commissioner Moeller Convenes Public Meeting Focusing on Resolving Natural Gas Supply Challenges for Electric Generators

Commissioner Philip Moeller of the Federal Energy Regulatory Commission (FERC) held a public meeting on September 18, 2014 to discuss ideas to facilitate and improve the way in which natural gas is traded and to explore the concept of establishing a centralized natural gas trading platform.  Although not an official FERC conference, the ideas at issue were an extension of FERC’s recent focus on gas-electric coordination.  During the well-attended meeting, Commissioner Moeller presided over a large roundtable discussion of stakeholders, including electric generation owners, natural gas producers, pipelines and marketers, who engaged in a spirited discussion of whether natural gas supplies are meeting the needs of electric generators and improvement in supply practices.  The central focus of the meeting was the creation of a natural gas information and trading platform containing bids and offers for the purchase and sale of commodity and capacity for receipt and delivery on points across multiple pipeline systems.

Participants agreed that the natural gas industry is evolving and an increasing share of natural gas is being supplied to electric generators—customers with different needs than the local distribution companies the natural gas pipeline industry was traditionally designed to serve.  Most participants further agreed that the needs of generators do not always align with pipelines’ traditional services.

Natural gas-fired generation owners voiced concerns regarding unknown or unreasonable commercial terms in pipeline service agreements, a lack of transparency surrounding available services and illiquidity in the natural gas market.  Pipeline representatives highlighted the availability of new services such as extra nomination cycles, no-notice service and the ability to reverse flow as examples of services intended to accommodate generators.  Nevertheless, the pipeline representatives also made the point that natural gas liquidity is outside pipelines’ control as they do not have title to the gas they transport.  Marketers and organized exchange representatives added that they have been responding to generators’ needs by making available bespoke products and exploring new standardized products to match generators’ demands.

In addressing possible solutions to transparency and liquidity problems, most meeting participants urged incremental change and expressed a preference for industry solutions over FERC’s regulatory intervention.  Electric generators preferred increased use of non-ratable service, no-notice service and new, shaped products.  Other proposals included eliminating the shipper-must-have-title rule, facilitating competition between capacity release and pipeline overrun services and encouraging generators to purchase firm transportation service rather than interruptible service.

FERC has established a docket number to allow interested parties to file written comments on any issue that was discussed at the meeting.  Comments are limited to five pages and are due by October 1, 2014.




The DOE Approves a Second LNG Export Project: A Sign of the Future?

by Daryl Kuo

As the world’s largest producer of natural gas, the United States has the potential to also become the world’s leading exporter of liquefied natural gas (LNG).  The Department of Energy (DOE), however, continues to proceed extremely cautiously with respect to authorizing LNG exports, particularly to countries that have not signed free trade agreements (FTA) with the United States.

To approve a project, the DOE must determine that it is not contrary to the public. While exports are presumed to be in the public interest, this presumption can be rebutted in comments filed by opponents to the proposed exports. The public interest test balances various factors, including (i) the impact of the liquefaction project on domestic natural gas demand, supplies, prices and resource base, (ii) the benefits of international trade, and (iii) the benefits to the domestic economy, national energy security and the global environment. The approval process is further impeded by the fact that the applications are processed in the order in which they are received, pursuant to an Order of Precedence issued by the DOE in December 2012. The DOE will not change this order absent a change in policy.

To date, the DOE has only approved two projects to export LNG to non-FTA-signatory countries.  In August 2012, the DOE authorized the Sabine Pass Liquefaction project, and in May 2013, the DOE conditionally approved the Freeport LNG Expansion project, which permits the export of 511 billion cubic feet of gas per year for a twenty year period.  The delay between both approvals stemmed from the DOE’s commissioning of two studies to assess the potential impact of LNG exports on domestic gas prices and the national economy.  Both studies yielded positive findings that encouraged LNG exports.

Although over twenty LNG export applications to non-FTA-signatory countries remain pending before the DOE, the Freeport approval may be indicative of the DOE’s shifting position regarding LNG exports to non-FTA countries.  The DOE’s review of the Freeport application focused on comparing Freeport’s arguments with the objections made by an opponent to the project, taking stock of concurrences by commentators and acknowledging the favorable study findings.  The DOE applied the rebuttable presumption standard strictly and held that the protestor’s evidence was insufficient to rebut the statutory presumption that LNG exports are consistent with public interest.  The DOE did not debate the validity of the arguments made by Freeport or the pro-export commentators; it did not question the significance and accuracy of the studies (in fact, it dedicated over 50 pages to justifying the studies’ methodologies and findings); and, most importantly, it did not lend much weight to the protestor’s objections.

Despite the pro-export tone of the Freeport approval, the DOE indicated that it would proceed cautiously in reviewing pending applications by assessing the cumulative impact of each application.   Energy Secretary Moniz has not commented on the timeline for reviewing pending applications, and some companies are threatening to go to court to speed up the approval process and strike down the Order of Precedence, which was issued after [...]

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Natural Gas Companies Settle Antitrust Suit Stemming from Joint Bidding

by Jon B. Dubrow and Cerissa Cafasso

On Monday, April 22, 2013, after rejecting the initial settlement agreement, Judge Richard Matsch (D. Colo.) approved a revised settlement of a suit brought by the U.S. Department of Justice (DOJ) against two energy companies for conspiring not to compete for mineral rights leases.  Gunnison Energy Corp. (GEC) and SG Interests I Ltd. and SG Interests VII Ltd. (collectively "SGI”) will each pay a fine of $275,000 to the DOJ to settle allegations of agreeing not to bid against each other in violation of antitrust law for natural gas leases on government land in western Colorado.  These fines are in addition to those related to alleged False Claims Act violations, for which SGI and GEC paid government fines of $206,250 and $245,000 respectively.  The new settlement is twice the amount of the fines in the original settlement.

McDermott Will & Emery wrote an article in February 2012 analyzing the DOJ’s initial complaint against the parties, and the competitive implications of joint bidding.  At the time, the parties had agreed to pay a total of $550,000 in fines.  The court rejected the settlement in December 2012 finding that it was not in the public interest.  "There is no basis for saying that the approval of these settlements would act as a deterrence to these defendants and others in the industry, particularly as GEC considers ‘joint bidding’ to be common in the industry."  Further, the settlement amount was "nothing more than the nuisance value of [the] litigation."  Additionally, as reflected in the newly approved deal, the court wanted the alleged Sherman Act violations and False Claims Act violations settled separately, with a payment for the Sherman Act claims separate from, and in addition to, any amount due under the False Claims Act.  At heart, it appears Judge Matsch wanted any settlement he approved to be meaningful enough to have a deterrent effect on future agreements.

This was the DOJ’s first challenge to an anti-competitive bidding agreement for mineral rights leases, but it is just one of the recent cases in which joint bidding activities have become the focus of antitrust scrutiny.  In Summer 2012, the DOJ opened an investigation into Chesapeake Energy’s acquisition of oil and gas properties in Michigan and the possibility that Chesapeake conspired with Encana Corp. to allocate bids on those properties.  In 2006, the DOJ began investigating the joint bidding practices of private equity firms in connection with leveraged buyouts.  That investigation led to class action suits against private equity firms.  One of those suits survived a motion for summary judgment last month.

It is important to note that the DOJ is paying attention to joint bidding practices and taking action.  As noted in the SGI/GEC matter, while joint bidding may in fact be common practice in the energy field, it is not necessarily lawful.  Each arrangement should be evaluated for potential anticompetitive effects.




Illinois to Act on Fracing – Or Not

by Thomas L. Hefty

The Illinois General Assembly could be on the verge of enacting legislation, the Hydraulic Fracturing Regulatory Act (H.B 2615), that some environmental groups are touting as an environmental best practices for regulating the shale oil and gas recovery method known as horizontal hydraulic fracturing (fracing). H.B. 2615, the result of months of negotiations between environmental groups and the oil and gas exploration and production (E&P) industry, was set to be voted on in the Illinois General Assembly in late March, but a last second amendment (favoring in-state licensed drilling companies) has stalled the bill’s progress. 

While HB 2615 is laudable for setting robust regulations on horizontal fracing operations, what should make it the betting favorite is that it is also a revenue bill – the second half of H.B. 2615 contains the Illinois Hydraulic Fracturing Tax Act. Under H.B. 2615, Illinois would finally join the majority of drilling states that tax severed oil and gas. Each Illinois well using horizontal hydraulic fracturing could produce several million dollars in severance taxes during the span of the well’s productive life.

Illinois is one of the few drilling states not to impose any severance or gross production taxes on its substantial oil and gas production. Illinois currently has about 32,000 wells producing between 10 and 11 million bbls of oil (15th nationally) and 2,120 million cubic feet of natural gas, ranking it 26th. That production would increase significantly if large-scale horizontal hydraulic fracturing were introduced in Illinois to the New Albany Shale formation. Technically recoverable shale gas in the New Albany Shale is estimated at up to 11 trillion cubic feet (for comparison, the Marcellus Shale in the East has 84 TCF). A majority of the drilling states, including Indiana and Kentucky, tax oil and gas production. Several others, most prominently Pennsylvania, are currently considering adopting oil and gas severance taxes.

Competing with H.B. 2615 are three other bills: two bills favored by those environmental groups not supporting H.B. 2615 that would put a two-year moratorium on any hydraulic fracturing and an E&P industry-sponsored bill that environmental and community groups strenuously oppose. One would think that with the support of the E&P industry and some environmental groups (including the Natural Resources Defense Council), plus the revenue enhancement features of the severance tax, H.B. 2615 should be a done deal. But given the current state of Illinois politics, taxes might not be the certainty that Ben Franklin once thought they were. 




New DOE Study Fuels Debate Over LNG Exports

by Bethany K. Hatef

The U.S. Department of Energy (DOE) engaged the controversy over exporting liquefied natural gas (LNG) with its December 5 publication of Macroeconomic Impacts of LNG Exports from the United States. Prepared for DOE by NERA Economic Consulting, the report concludes the domestic economy will benefit from LNG exports and thereby paves the way for approval of LNG export applications pending DOE approval. But, given the lead times for building export terminals and that only four of the 15 pending applications are expected to be approved in 2013, significant exports are unlikely in the near term. To be considered, initial public comments on the report must be submitted to the Department by January 24, 2013, reply comments by February 25, 2013.

The report evaluated economic impacts “under a wide range of different assumptions about levels of exports, global market conditions, and the cost of producing natural gas in the U.S.” NERA modeled impacts using its Global Natural Gas Model and its general equilibrium model of the domestic economy. NERA considered the 16 economic scenarios addressed in DOE’s first study, issued in January 2012, as well as 47 global scenarios NERA developed.

The report concludes that in all 63 scenarios evaluated, increased LNG exports produced net domestic economic benefits. Even scenarios of unlimited export of LNG consistently produced higher net economic benefits than scenarios involving limited LNG exports. The report projects some negative effects of increased LNG exports on the U.S. economy, noting that large amounts of exports would slightly raise natural gas prices (e.g., with significant increases in LNG exports, prices could jump by more than $1 per thousand cubic feet over five years, an increase of more than 25 percent) and negatively affect utilities and “energy-intensive” manufacturers (i.e., manufacturers with energy expenditures exceeding 5 percent of output and significant exposure to foreign competition).

Rising domestic natural gas prices would have a ceiling, the report observes, since “importers will not purchase U.S. exports if U.S. wellhead price rises above the cost of competing supplies.” Energy-intensive industries are not projected to lose employment or output exceeding one percent per year. Additionally, the report projects that LNG exports will positively affect some segments of the domestic economy and improve consumer welfare, outcomes that, the report concludes, outweigh the losses associated with increased natural gas prices. The report estimates that LNG exports could produce between $10 and $30 billion in annual export revenues.

The report is certain to fuel already hot contention over whether DOE should authorize LNG exports. Dow Chemical has already decried the report’s conclusions, warning that increased domestic natural gas prices would impede energy-intensive manufacturers’ ability to keep up with their foreign counterparts. As mentioned in last month’s update, Senator Ron Wyden (D-OR) and Congressman Edward Markey (D-MA) are also critics of increased LNG exports, noting that a rise in LNG exports would essentially constitute a transfer of wealth from consumers to oil and gas companies. Environmental groups, who oppose the practice of hydraulic fracturing, which has contributed to the current abundance of natural gas in the [...]

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New Research Finds Shale Natural Gas Production Emits Less Fugitive Methane that Previously Reported

by James A. Pardo and Brandon H. Barnes

Shale natural gas production emits significantly less fugitive methane than previously thought, concluded researchers at the Massachusetts Institute of Technology (MIT) in a November 26, 2012, study published in Environmental Research Letters.  According to the researchers, "it is incorrect to suggest that shale gas-related hydraulic fracturing has substantially altered the overall [greenhouse gas] intensity of natural gas production." 

 Methane has been singled out as one of the most powerful greenhouse gases (GHG) because of its "global warming potential" – or the relative heat trapped in the atmosphere by a gas – which is 20 times greater than that of carbon dioxide.  Fugitive methane emissions are losses of methane gas that may occur during flowback (the return of fluids), during drill-out following fracturing, and during well-venting to alleviate well-head pressure.  Fugitive emissions can also occur as a result of equipment leaks, transportation or storage losses, and processing losses, but in much smaller quantities. 

An earlier study by Cornell University professor Robert Howarth, which garnered much media attention, reported that shale gas production had a lifetime carbon footprint greater than coal production, mainly as a result of fugitive methane emissions that Howarth had estimated to be as great as 4,638 Mg per well.  In contrast, the MIT study determined that actual fugitive methane emissions average approximately 50 Mg per well after taking into account flaring and green completions technology, both of which are widely used by industry and required under most state regulatory regimes (as well as under new Environmental Protection Agency rules).  The MIT researchers evaluated actual production data from approximately 4,000 horizontal shale natural gas wells, and found a potential for about 228 Mg of fugitive methane emissions per well.  The researchers cautioned that estimates about fugitive methane emissions had been "inappropriately used in analyses of the GHG impact of shale gas" insofar as actual emissions are reduced — by an average of 178 Mg per well — by flaring and green completion technology.        

Hydraulic fracturing stakeholders need to understand the body of publicly available science, as a growing body of research will inform how EPA and other state and federal regulatory agencies will regulate the industry.




LNG Exports Continue to Await DOE Approval

by Daryl Kuo

The discovery and accessibility of vast domestic shale gas reserves in the United States has motivated states and industry alike to lobby heavily for the approval of liquefied natural gas (LNG) exports.  LNG exports to non-Free Trade Agreement (FTA) countries, including China and Japan, are of particular interest because estimates for exports to those countries are as high as 16 billion cubic feet per day, more than ten times greater than all U.S. LNG exports in 2011.  So far, the U.S. Department of Energy (DOE) has approved only one LNG export project to non-FTA countries, and that approval is being challenged. Meanwhile, more than a dozen applications sit in DOE’s queue pending the release of a critical study by the end of the year. The debate over exports to non-FTA countries is likely to become more intense in the coming months once that study is released and subjected to a public comment period prior to any decisions by the DOE on the pending applications.

Section 3 of the Natural Gas Act (NGA) prohibits the export of LNG without the prior approval of the DOE, which must approve an export project unless it determines that the proposed export will be inconsistent with the public interest.  To date, the DOE has authorized only one project to export LNG to non-FTA countries, the Sabine Pass liquefaction project on the border of Louisiana and Texas. However, on September 6, 2012, Sierra Club requested a rehearing and stay of the DOE’s order authorizing Sabine Pass to export LNG to non-FTA countries. The DOE issued a tolling order on October 5, 2012 to extend the date by which it must act on Sierra Club’s request, which would otherwise have automatically been denied after 30 days. Sierra Club filed a motion to supplement the record in that case on November 1, 2012.

Fourteen other applications for projects involving non-FTA countries are currently pending DOE review (the most recent application was submitted by Golden Pass Products LLC, an affiliate of Exxon Mobil, on October 25, 2012), but the approval process is frozen while the DOE waits for the second half of a two-part study on the domestic impact of LNG exports to non-FTA countries.  The first part of the study, conducted by the U.S. Energy Information Administration, found that increased exports would raise electricity bills in the U.S. by an average of 1 percent to 3 percent annually between 2015 and 2035.  The DOE is delaying any further action until the release of the second part of its study looking at the macroeconomic impact of LNG exports, which is not expected until the end of the year. 

Given the political sensitivity of exporting domestic resources, particularly to non-FTA countries, lawmakers and industry have expressed concern about whether DOE could withdraw an approval. In a letter to Congressman Edward J. Markey (D-MA), dated February 24, 2012, the DOE responded to this concern by referencing its Sabine Pass order and noting that its authority to issue supplemental orders modifying previous [...]

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The Office of Gas and Electricity Markets of Great Britain Consults Further on its Electricity and Gas Retail Market Review

by Caroline Lindsey

On October 26, 2012, the Office of the Gas and Electricity Markets (Ofgem) published updated proposals for changes to the regulation of the non-domestic electricity and gas retail markets in Great Britain.  The Retail Market Review Proposals (RMR Proposals) are part of Ofgem’s RMR program, which also includes proposals for the domestic markets.

The RMR Proposals follow Ofgem’s initial consultation on proposals for the non-domestic market in November 2011, and its Energy Supply Markets Probe in 2008.  Since the initial consultation, Ofgem has been conducting further research, gathering relevant information from suppliers and considering the responses to the initial consultation.

The principal RMR Proposals are:

  • Increased protection for small business consumers – condition 7A of the standard conditions of electricity and gas supply licences (SLC) currently provides protection for micro business consumers when dealing with suppliers.  Ofgem is proposing to expand the number of small business consumers who have the benefit of those protections, by introducing a new definition of small business consumer.  The new definition is intended to capture existing micro business consumers, as well as a wider category of consumers whose annual consumption of electricity and gas is equal to or less than the relevant threshold (100,000 kWh per annum for electricity and 293,000 kWh per annum for gas).  Ofgem also proposes to introduce additional protections, including an obligation to include contract end dates and related notice periods on customer bills.
  • Introduction of binding standards of conduct when dealing with small business consumers – suppliers will, by way of a new SLC 7B, be required to comply with standards of conduct when engaging in the designated activities of billing, contracting and customer transfers with small business consumers.  The overarching objective of the standards of conduct, which will be expressly stated in SLC 7B, is to ensure that each small business consumer is treated fairly.  The standards of conduct include an obligation on the licensee to carry out the designated activities “in a Fair, honest, transparent, appropriate and professional manner.”  Ofgem has indicated that it will give guidance on the meaning of at least some of those terms. 
  • Development of a common code of conduct for third party intermediaries (TPI) – Ofgem proposes to develop options for a common code of conduct for TPIs, who broker contracts between non-domestic consumers and suppliers.  It will also conduct a wider review of the regulatory framework applicable to TPIs, including considering whether more direct regulation by Ofgem (in addition to the code of conduct) is needed.
  • Continuing monitoring of suppliers’ compliance with the customer transfer process – Ofgem proposes to increase its level of monitoring of suppliers’ compliance with the customer transfer objection requirements set out in SLC 14.  No changes to the SLCs are proposed at this stage.

Ofgem intends to publish an issues paper on the TPI regulatory framework review in the first half of 2013. It proposes to introduce the new protections for small business consumers (the first two items in the [...]

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