On February 23, 2018, the Environmental Protection Agency (EPA) issued a prepublication notice to change the Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources rule (“2016 Rule”). The rule, soon to be published in the Federal Register, addresses the so-called “delayed repairs” requirement of the rule, and will eliminate the requirement that well and compressor station owners or operators repair leaks during unscheduled or emergency blowdowns, shutdowns, or shut-ins. The new rule will allow the owners and operators to wait to repair a leak until the next scheduled blowdown, shutdown or shut-in, or do so within two years, whichever is earlier. The changes reflect the EPA’s resolution of industry complaints received in response to a November 2017 request for comment, including concerns related to service disruptions and higher shutdown emissions caused by depressurizing the equipment in order to repair it. Additional industry comments that relate to other aspects of the 2016 Rule, however, remain to be addressed in subsequent EPA rulemakings.
We are pleased to share a recording of our energy briefing that took place last week, “The Global Energy Industry 2018: A Look to the Year Ahead.” Speakers included Akin Gump tax partner Alison Chen, oil and gas partner John Goodgame, global project finance practice co-head John Marciano, along with oil and gas partner Christine LaFollette as moderator. The topics covered included:
- Tax reform: Impact on Energy Companies and Power Projects
- Shifting Focus from Production to Returns: Implications for the Exploration & Production Business
To view the recording, please click here.
Akin Gump oil and gas partner Marc Hammerson has co-written the article “Addressing the Generation Gap,” published by Petroleum Review.
Under the Petroleum Act 1998, the Secretary of State is authorized to grant licenses for the exploitation and production of hydrocarbons. The legal characteristic of such licenses has been an open question. If petroleum licenses are a statutory instrument, they would be subject to principles of public and administrative law. Whereas, if deemed to be a creation of private law, petroleum licenses would be governed by the law of contract. There are a number of important consequences resulting from the legal characterization. These include (as the case below illustrates) the procedure for amendments of license terms and potential administrative law arguments that the Secretary of State should be prohibited from acting ultra vires (i.e., outside his powers).
In June 2017, the Japan Fair Trade Commission (JFTC) issued its conclusion on an earlier market study on liquefied natural gas (LNG) resale restrictions and cautioned that (i) destination clauses, (ii) diversion clauses, (iii) profit-sharing clauses and (iv) take-or-pay clauses in LNG sale contracts may fall afoul of the country’s antimonopoly laws.
A recent report on decommissioning provides up-to-date predictions for the future costs of dismantling infrastructure in the United Kingdom Continental Shelf. It is the first financial estimate by the Oil & Gas Authority (OGA) since the regulator was established in 2016. The methodology used is different from that of previous surveys.
The report is noteworthy in its application of the new statutory requirement of Maximising Economic Recovery (MER). As applied to decommissioning, this requires that persons undertaking an activity must do so in a cost-effective way. This includes employing new and emerging technology. The report emphasizes the potential to reduce costs by the application of MER.
The Australian Domestic Gas Security Mechanism at a Glance
On June 5, 2017, the Australian government released draft amendments to the existing Customs (Prohibited Exports) Regulations 1958 (the “Amended Regulations”) that proposes a mechanism (the Australian Domestic Gas Security Mechanism or ADGSM) that calls for liquefied natural gas (LNG) export control restrictions in circumstances where the Resources Minister reasonably believes that there will not be sufficient gas supply for the Australian domestic market in any given year.
The ADGSM – When and Why?
The ADGSM is expected to be effective from July 1, 2017, with a five-year sunset clause (until January 1, 2023). There will be a review in 2019 to assess the overall effectiveness and efficiency of the ADGSM against its stated objectives.
The ADGSM is designed to be a short-term, targeted solution to ensure security of the gas supply at an affordable price. Many have seen this as a response to national energy security concerns as a result of the surging domestic gas price in Eastern Australia, evidenced by an 80 percent price increase over the past 18 months. LNG exporters drawing gas (in net terms) from the domestic market are therefore required under the ADGSM to limit export or find offsetting sources of new gas.
The Declaration – Consultation – Determination Process
Under the ADGSM, LNG export restrictions will be imposed in only a “domestic shortfall year.” In order to arrive at such a conclusion, the Resources Minister will have to:
- formally issue a declaration to announce his/her intention to consider whether the forthcoming year will be a domestic shortfall year (the “Declaration”)
- consult relevant market bodies, government agencies, potentially impacted industry players, other relevant Australian government ministers and other stakeholders to seek their view on the then-current and forecast gas market conditions and any potential for a gas market shortfall (the “Consultation”)
- if he/she has reasonable grounds to believe that there is a domestic gas market shortfall after the Consultation, make a determination that gas export controls will apply in a particular year (the “Determination”).
The Declaration – Consultation – Determination process follows a statutory timeline. The Declaration should be issued before October 1, and the Determination has to be made no later than November 1 of the year preceding the domestic shortfall year.
Export Permissions in a Domestic Shortfall Year – the Licensing Regime
In any given domestic shortfall year, export controls will apply. Under the ADGSM, this means that LNG export activities are prohibited across Australia (even though the shortfall exists in only certain parts of the country) without an Export Permission. An Export Permission will take the form of either an Unlimited Volume Export Permission (a “UV Permission”) or an Allowable Volume Export Permission (an “AV Permission”).
UV Permission. This will typically be granted to an LNG project that is a net contributor to the domestic gas market and that is unable to deliver gas at a reasonable price to a market experiencing a shortfall. A UV Permission allows for the export of an unlimited volume of LNG from a particular project over the market shortfall year.
AV Permission. This will typically be granted to an LNG project connected to markets experiencing a shortfall, including an LNG project that is in net deficit to the domestic gas market. An AV Permission will set a maximum LNG volume that can be exported from a specific project over the market shortfall year. The maximum amount would customarily represent the difference between the in-net-deficit exporter’s forecast total export quantity and its allocated share of/contribution toward the gas shortfall amount to be met by export controls as determined by the Resources Minister under the ADGSM.
Net Market Position of an LNG Project. In any given domestic shortfall year, the Resources Minister will determine whether each LNG project is a net contributor to, or in net deficit to, the domestic gas market, based on its upstream tenements. According to this classification, different LNG projects will be entitled to a different type of Export Permission in such a domestic shortfall year. An LNG project is in net deficit if:
- its total gas used is greater than the sum of gas produced by upstream tenements (i) owned by the LNG project, (ii) owned by the LNG project or third parties and is contracted directly to supply the LNG project and primarily developed for exports purposes, and (iii) owned by third parties and is contracted directly to supply to the LNG project and the contract was entered into before a final investment decision was made in relation to that LNG project or
- its gas purchases from the domestic market are greater than its gas sales to the domestic market.
Conversely, if an LNG project is not in net deficit, it will be regarded as a net-contributor LNG project.
Enforcement of the Licensing Regime Under the ADGSM
Under the Amended Regulations, noncompliance with a condition of an Export Permission may lead to a revocation of the Export Permission. Alternatively, the Resources Minister may grant a replacement Export Permission with different conditions attached, such as granting a lesser LNG export volume or imposing a stricter information reporting requirement.
Implications for Australian LNG Exporters
- The ADGSM is of nationwide application. If a given year is determined to be a domestic shortfall year, all LNG exports will be prohibited, unless exported in accordance with an Export Permission, and all in-net-deficit LNG projects will be allocated a gas shortfall amount that will be counted toward the reduction in the allowable LNG export volume in the relevant exporter’s Export Permission. As such, an in-net-deficit exporter located in a gas surplus region (e.g., Western Australia) will still be affected, since the ADGSM will impose on it an obligation to offset a portion of the country’s gas shortage amount to be met by export controls. Conversely, if an LNG exporter is classified as a net contributor, regardless of where it is situated geographically, it is still very likely to be granted a UV Permission and therefore can export an unlimited volume of LNG from gas produced from its upstream tenements even in a domestic shortage year.
- The Rise of Resource Nationalism. The ADGSM follows a new wave of resource nationalism around the Asia-Pacific region in the name of national energy security. Earlier this year, Indonesia banned exports of unprocessed copper ore in a mining dispute, and the Philippines restricted open pit mining and curbed nickel ore shipments. It remains to be seen whether the ADGSM will be an effective means to deal with the gas shortage in Australia or whether it would be a mechanism adding complications and uncertainty to the Australian domestic gas market. The enforcement of the ADGSM also has some clear World Trade Organization (WTO) and Australia-U.S. FTA angles, since countries are generally prohibited under these trade rules from restricting imports/exports except through duties. While (albeit limited) exceptions do exist in the WTO for purposes of preservation of natural resources and ensuring domestic supply, with respect to the former, there is recent WTO case jurisprudence (e.g., China—Measures Related to the Exportation of Rare Earths, Tungsten and Molybdenum (WT/DS431-433)) that make clear that such restrictions are permissible only if there are also effective restrictions imposed on domestic production and consumption. With respect to the latter, countries would essentially have to establish that the restricted products are “critical” to the exporting country and that the restrictions are “temporary” for the stated purpose only. Finally, while the ADGSM hints at potential national security concerns, it is unclear whether this is, in fact, an argument being put forward by the Australian government, since such positions—while mostly self-judging—will only encourage other trading partners to arbitrarily invoke the same with respect to certain of their export products.
- Wide Government Discretion in the Decision-Making Process. The ADGSM contains two decision points: the Resources Minister’s determination that (i) a particular calendar year shall be classified as a domestic shortfall year, and (ii) an Export Permission shall be granted to a particular LNG exporter during such a domestic shortfall year. In each case, even though the Resources Minister is obliged to consult various stakeholders in the industry and across the government within certain statutory time frames, he/she has considerable discretion during the decision-making process. The consultation period may be as short as 30 days before the Resources Minister can formally announce such radical export control measures with far-reaching implications.
- Ability for LNG Projects to Adjust Commercial Operations in Response to Government Decisions. Under the ADGSM, the Declaration process will be made prior to October 1, and the Determination process will be made no later than November 1 of the year preceding the domestic shortfall year. In addition, the Resources Minister may, at any time, revoke his/her decision that a particular calendar year is a domestic shortfall year. LNG projects may not have sufficient time to adjust commercial operations around these government decisions/determinations, which may eventually lead to an even more volatile gas market domestically.
- Implications on LNG Supply Obligations Under Long-Term Offtake Arrangements. Most Australian LNG volumes are exported under long-term supply contracts, where failure to supply in a non-force majeure scenario triggers a seller obligation to procure replacement LNG cargoes with incremental costs borne by the seller. Although “acts or omissions of a Government Authority” are often within the scope of a “force majeure” event, a failure to supply resulting from the lack of economically recoverable reserves from a seller’s upstream tenements would (under most long-term LNG supply contracts) disqualify a force majeure argument. This suggests that a force majeure argument would be difficult to raise in response to an export restriction imposed under the ADGSM, meaning that any LNG exporters that cannot meet their LNG export obligations will need to procure replacement LNG cargoes and incur any incremental replacement costs. How significant these shortfall amounts will be as a result of the application of the ADGSM remains to be seen, but some analysts have suggested that the impact will be limited to Australian suppliers having to buy just one or two additional cargoes a year to make up the shortfall.1
On June 19, 2017, the Comisión Nacional de Hidrocarburos (CNH) completed the Presentation and Opening of Bid Proposals for the First Tender of the Ronda Dos (“Round 2.1”), which was first announced on July 20, 2016. Round 2.1 attracted 36 bidders: 20 individual companies and 16 consortia, including Petroleos Mexicanos, DEA Deutsche Erdoel, Talos Energy, Noble Energy, Chevron, Shell, Total and ConocoPhillips.
Round 2.1 included 15 contract areas with an estimated four billion BOE of dry gas, wet gas, light oil, heavy oil and extra heavy oil located in the shallow waters of Veracruz, Tabasco and Campeche.
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