Tag: oil

Oil Pollution Act: Tips for Spill Response, Compliance, and Enforcement

Oil spills commonly occur when least expected and, even in smaller quantities can significantly disrupt business operations and create risks for enforcement and/or litigation. It’s important that companies are prepared and know the environmental requirements for when the least expected happens, including understanding what actually is “oil” (hint: it’s broader than you might think!), who to notify, legal authorities at play, and best practices to ensure compliance and minimize exposure to regulators and/or private parties.

What is “Oil” Anyway?

Section 311 of the Clean Water Act (CWA) and the Oil Pollution Act (OPA) make up the federal statutory framework for oil spills. However, many companies may not realize that both petroleum-based and non-petroleum-based substances are regulated as “oil” under the CWA and OPA. As a result, many companies may not realize that they are subject to these laws and, therefore, fail to adequately prepare for compliance and/or response both pre- and post-spill.

Specifically, Section 311(a)(1) of the CWA defines oil as “oil of any kind or in any form, including, but not limited to, petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes other than dredged spoil.” 40 CFR § 112.2 further defines oil as “oil of any kind or in any form, including, but not limited to: fats, oils, or greases of animal, fish, or marine mammal origin; vegetable oils, including oils from seeds, nuts, fruits, or kernels; and, other oils and greases, including petroleum, fuel oil, sludge, synthetic oils, mineral oils, oil refuse, or oil mixed with wastes other than dredged spoil.” This definition is notably broader than what many may consider “oil” (i.e., crude oil and refined petroleum products) and encompasses animal fats, vegetable oils, and non-petroleum oils.

When to Notify?

The CWA and OPA require companies to notify the National Response Center (NRC) of oil spills as soon as they are discovered (i.e., within 15 minutes). This applies to all discharges that reach navigable waters of the U.S. (WOTUS) or adjoining shorelines and (1) cause a sheen; (2) violate applicable water quality standards; or (3) cause a sludge or emulsion beneath the surface of the water or upon adjoining shorelines. In practice, this typically results from a sheen, which 40 C.F.R. § 110.1 defines as an “iridescent appearance on the surface of water.” The Oil Pollution Prevention regulations (discussed further below) also identify discharges from regulated facilities that require reporting, though there are exceptions—for example, when the discharge is in compliance with a permit under Section 402 of the CWA.

Under state and local laws, notification may be much more stringent. For example, California requires immediate reporting of “any significant release or threatened release” of a hazardous material, which includes oil. This can be subjective and requires a fact- and legal-specific evaluation of whether the release qualifies as “threatened” and/or “significant.” In Georgia, immediate notification is required either when the oil creates a “significant sheen on top of state waters” or when the amount discharged is unknown—further creating different criteria for when reporting is required. Regardless of what triggers notification, it is important that companies understand that different agencies—federal, state, and local—may each have different reporting requirements, and accurate and timely reporting is absolutely crucial. Often, failure to timely report is the first violation sought by agencies and can result in increased penalties and additional scrutiny.

What Authorities Are at Play?

At the federal level, two agencies primarily exercise authority over oil spills—the U.S. Environmental Protection Agency (EPA) and U.S. Coast Guard (CG). Depending on the location of the spill, the EPA or CG may lead federal oversight with the EPA overseeing inland spills and CG overseeing offshore spills. The Pipeline and Hazardous Materials Safety Administration and Federal Railroad Administration may also exercise authority for pipeline or railroad releases, respectively.

As mentioned above, Section 311 of the CWA and OPA—enacted in 1990 in response to the Exxon Valdez oil spill—make up the federal statutory framework for oil spills. In practice, these authorities are best categorized into two areas: (1) oil spill response; and (2) oil spill prevention and preparedness. It is important for companies to understand the expectations for both (discussed in more detail below), and the National Oil and Hazardous Substances Pollution Contingency Plan (often referred to as the National Contingency Plan or NCP), which outlines the federal government’s cleanup strategy for responding to oil spills, including other cleanups under CERCLA. The goal of the NCP is to ensure that resources are available and responses are consistent. Thus, when the federal government oversees a cleanup, the federal On-Scene Coordinator will expect that all response efforts, including those conducted by the responsible party, are consistent with the NCP.

At the state level, most utilize their respective water laws to address oil spills, though some states, like Louisiana, have laws comparable to OPA. At the local level, municipalities have notification and emergency response authorities that will be applicable. In the end, it’s very important that companies understand that several layers of government may have some form of oversight depending on the size, impact, and location of an oil spill.

OPA v. CWA

While the CWA and OPA are complimentary, including OPA amending the CWA, companies should understand the goals and implications of both. Generally, the CWA focuses on oil spill enforcement for cleanups and penalties, and the OPA broadens national and regional capability for preventing, responding to, and paying for oil spills.

For the CWA, Section 311(b)(3) expressly prohibits the discharge of oil (or hazardous substances) into or upon WOTUS and adjoining shorelines in quantities that may be harmful.1 For oil, this generally means discharges to WOTUS that cause sheening or violate applicable water quality standards. Sections 311(c) and (e) of the CWA provide extensive authority to the federal government to respond to these discharges, including threatened discharges, by issuing orders—either unilaterally or by consent—to owners, operators, or persons in charge of the facility from which the discharge occurs.

Sections 311(b)(6) and (7) of the CWA further empower the federal government to pursue significant penalties—both administrative and civil—for spills that reach WOTUS and/or when responsible parties fail to comply with an order. If gross negligence or willful misconduct is involved, you can expect even greater penalties—commonly more than three-fold—not to mention possible criminal liability. Internally, the EPA utilizes the Civil Penalty Policy for Sections 311(b)(3) and (j) of the CWA and factors outlined in Section 311(b)(8) of the CWA, including the seriousness of the violation, economic benefit to the responsible party, history of prior violations, and efforts to minimize or mitigate the discharge, to evaluate enforcement and penalty calculations.

Akin to the CWA, Section 2702(a) of OPA also makes responsible parties liable for removal costs and natural resource damages resulting from any discharge of oil, including a substantial threat of discharge, to WOTUS and adjoining shorelines. Notably, this includes not only costs incurred by the federal government, but also costs or damages to private parties, including damages for the loss of personal property, loss of revenues/profits due to injury, and cost of additional services during or after a spill. OPA further aims to strengthen national and regional response strategies, amend the National Oil and Hazardous Substances Pollution Contingency Plan, require facilities to develop prevention and response plans, and establish a fund for damages and cleanup costs—each discussed below.

While it is typically always the priority of the federal government to have responsible parties pay for and conduct their own spill cleanups, when a responsible party is unknown, unable, or refuses to pay, funds from the Oil Spill Liability Trust Fund (OSLTF) can be utilized to pay for the response. The OSLTF is managed by the CG’s National Pollution Funds Center (NPFC) and the NPFC thereby manages any oversight or cleanup costs incurred by the federal government. Thus, if an oil spill occurs at your facility and the federal government incurs costs responding or overseeing, the NPFC will be the entity that seeks recovery of those costs—even if the EPA later pursues penalties for the same discharge pursuant to Sections 311(b)(6) and (7) of the CWA. In addition, when a non-liable party performs a cleanup or incurs damages as a result of an oil spill, that party may file a claim for reimbursement directly against the responsible party and/or seek reimbursement from the NPFC.

Lastly, regarding liability, both the CWA and OPA are strict liability and provide limited liability defenses for acts of God, acts of war, or acts/omissions of third parties—comparable to CERCLA. Even so, it’s important to note that Section 309(g)(6) of the CWA states that the federal government may not seek enforcement, including penalties, if the state “has commenced and is diligently prosecuting an action” under a comparable state law. This includes issuing a final order or directing a responsible party to pay a penalty. As mentioned above, states typically pursue oil spill violations via their respective water laws, which may be considered comparable. State penalties may often be substantially less than those sought by the federal government—thus, early engagement with the state can be advantageous depending on the circumstances.

Oil Pollution Prevention Regulations

Section 311(j) of the CWA and OPA, as outlined in 40 C.F.R. Part 112, require facilities that store oil in significant quantities to prepare Spill Prevention, Control, and Countermeasure (SPCC) Plans to prevent accidental releases from reaching WOTUS or adjoining shorelines. Facilities with a greater risk of release and impact to WOTUS may also be required to develop a Facility Response Plan (FRP) to prepare for “worst-case spills.” At the outset, companies should confirm whether these regulations are applicable to their operations and facilities.

SPCC plans are required for facilities that are: (1) non-transportation-related (i.e., they store, process, or consume oil rather than simply move it from one facility to another); and (2) collectively store more than 1,320 gallons of oil above ground or 42,000 gallons below ground that could reasonably be expected to discharge oil to a WOTUS or adjoining shorelines. This can include oil drilling and production facilities, oil refineries, industrial, commercial, and agricultural facilities storing/using oil, facilities that transfer oil via pipelines or tank trucks (including airports), and facilities that sell or distribute oil, like marinas. Practically, these regulations require facilities to have a written plan certified by a professional engineer (apart from qualified facilities), maintain adequate secondary containment for oil storage, maintain updated lists of the federal, state, and local agencies that must be contacted in case of a spill, and follow regular inspection requirements, among other requirements.

In addition to SPCC, FRP plans are required for facilities that could reasonably expect to cause “substantial harm” to the environment by discharging oil into or upon WOTUS. They either have: (1) total oil storage capacity greater than or equal to 42,000 gallons and transfer oil over water to/from vessels; or (2) total oil storage capacity greater than or equal to 1 million gallons and either do not have sufficient secondary containment, are located at a distance such that a discharge could cause “injury” to habitat or shut down a drinking water intake, or within the past five years, have had a reportable discharge greater than or equal to 10,000 gallons. If so, given that FRP is self-identifiable, the facility must prepare and submit its FRP plan to its applicable EPA regional office. Among other things, these plans include evaluating , medium, and worst-case discharge scenarios, descriptions and records of self-inspections, drills, and response training, and diagrams of the facility site plan, drainage, and evacuation plan.

EPA commonly conducts inspections at subject facilities to ensure that SPCC and FRP plans are effectively implemented. Should your facility have an oil spill, plan on an inspection very soon to evaluate compliance and mitigation efforts with your respective requirements.

Suggested Actions

Beyond being aware of the above implications and requirements, below are several actions to consider to ensure compliance and minimize possible enforcement and/or litigation when the least expected occurs.

  • Act Fast: Should an oil spill occur, regardless of size, act fast to respond, mitigate, and determine if notification is required. This includes immediate internal coordination with those responsible for responding, as well as outreach to your environment counsel and/or consultant. If the determination for reporting is close, it is recommended that you report (with a qualified caveat) rather than withhold.
  • Education and Training: Ensure your staff is trained to effectively respond to, report, and prevent oil spills. Oil spills happen despite best attempts otherwise. When the inevitable happens, make sure facility staff are prepared to respond and mitigate the potential impacts of the spill, including having spill reporting hotlines and other contact numbers easily accessible and staff trained on where all information is located. Also, learn from past spills and/or near spills by conducting evaluations and identifying lessons learned to be utilized to prevent future spills.
  • Prepare for Outside Communication: If the spill is significant or causes public impacts, be prepared for outreach by the public, including local news and community groups. Notifications to the NRC are available online and impacts to public or private property often lead to alerts to local news and organizations. Ensure your public affairs contact(s) are aware and develop necessary communication, including desk statements, should the spill create public attention.
  • Review Compliance: Evaluate your current compliance with federal, state, or local requirements, including the development, assessment, and update (if needed) of SPCC and/or FRP response plans. This includes determining if either or both are required at your facility. Should a spill occur, it is important to make sure your response plans are up-to-date and ready for implementation.
  • Regular Audits and Updates: Periodically audit your spill response and prevention measures (SPCC and FRP plans), including any changes to facility operations, secondary containment features, or volumes of oil stored, to identify and correct inaccuracies and ensure that your plans are up-to-date. For FRP, this includes submitting updates to the appropriate EPA regional office within 60 days of each change that may materially affect the response to a worst-case discharge.
  • Insurance: Though not always necessary, consider appropriate insurance coverage to mitigate potential financial liabilities.
  • Consultation: If you have any doubts about your obligations during an oil spill or need assistance with compliance, please do not hesitate to contact your environment counsel or consultants for guidance and support.

1 While this discussion focuses on the impacts of oil spills, it’s important to remember that Section 311 of the CWA (though not OPA) also applies to hazardous substances—discharges to a WOTUS that exceed a reportable quantity pursuant to 40 C.F.R. § 117.3—though the federal government may typically utilize the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA or Superfund), or combination thereof, to pursue such releases.

© 2024 Beveridge & Diamond PC
For more news on Oil Spills, visit the NLR Environmental, Energy & Resources section.

Court of Appeals Rules That Oil and Gas Company Has Ongoing Obligation to Restore Property Despite General Release of Damages in Surface Use Agreement

On April 11, 2022, the Fourth District Court of Appeals issued a significant decision in Zimmerview Dairy Farms, LLC v. Protégé Energy III LLC establishing that a general release of damages signed in connection with a pad site surface use agreement did not release the oil and gas company from its ongoing obligations to remediate and restore damage to a landowner’s property.

In the Zimmerview case, Plaintiff Zimmerview Dairy Farms (“ZDF”) signed a surface use agreement with Defendant Protégé Energy III LLC (“Protégé”) permitting Protégé to construct and operate a pad-site for Utica Shale wells on a portion of the ZDF farm. The agreement consisted of three documents: a recorded surface use agreement (favorable to Protégé); a confidential supplemental agreement (with terms favorable to ZDF); and a damage release under which ZDF released Protégé from the anticipated damages already paid for by Protégé. This three-document structure is typical, especially for pipelines easements, and one which many oil and gas companies insist on. Often, the damage release is explained by landmen as an unimportant formality and that the company is still going to fix the land as required under the unrecorded agreement. However, what a landman says, what an agreement says and what a company does can differ dramatically.

In Zimmerview, Protégé proceeded to construct and operate its pad-site without adequately remediating, restoring and reseeding the areas disturbed during construction, including the slopes of the pad-site. Over several years, Protégé’s failure to remediate resulted in significant topsoil damage, invasive weed infestations and ongoing erosion, which rendered large portions of the ZDF farm unusable. Protégé refused to pay or fix the ZDF farm, claiming that the damage release signed by ZDF released Protégé from any obligation to remediate or pay for damages caused to the ZDF farm. When ZDF filed suit and won at trial, Protégé appealed.

On appeal, Protégé once again argued that ZDF had released Protégé from all damages resulting from construction and operation of the pad-site including damages from not remediating the ZDF farm. Despite the broad language of the release, however, the Court of Appeals rejected Protégé’s argument on the basis that the damage release, signed when the surface use agreement was executed, could not have been intended to release Protégé from damages that resulted from the ongoing obligations and requirements Protégé had just agreed to under the surface use agreement. Accordingly, the Fourth District affirmed the trial court judgment (and $800,000 verdict for damages) against Protégé. Given the common use (and abuse) of similar damage releases by both operators and pipeline companies, this decision is a welcome addition to Ohio caselaw and should assist (and hopefully encourage) Ohio landowners to insist on producers and pipeline companies meeting their construction and remediation obligations.

©2022 Roetzel & Andress
For more articles about court cases, visit the NLR Litigation section.

EV Buses: Arriving Now and Here to Stay

In the words of Miss Frizzle, “Okay bus—do your stuff!”1 A favorable regulatory environment, direct subsidy, private investment, and customer demand are driving an acceleration in electric vehicle (EV) bus adoption and the lane of busiest traffic is filling with school buses. The United States has over 480,000 school buses, but currently, less than one percent are EVs. Industry watchers expect that EV buses will eventually become the leading mode for student transportation. School districts and municipalities are embracing EV buses because they are perceived as cleaner, requiring less maintenance, and predicted to operate more reliably than current fossil fuel consuming alternatives. EV bus technology has improved in recent years, with today’s models performing better in cold weather than their predecessors, with increased ranges on a single charge, and requiring very little special training for drivers.2 Moreover, EV buses can serve as components in micro-grid developments (more on that in a future post).

The Investment Incline

Even if the expected operational advantages of EV buses deliver, the upfront cost to purchase vehicles or to retrofit existing fleets remains an obstacle to expansion.  New EV buses price out significantly more than traditional diesel buses and also require accompanying new infrastructure, such as charging stations.  Retrofitting drive systems in existing buses comparatively reduces some of that cost, but also requires significant investment.3

To detour around these financial obstacles, federal, state, and local governments have made funding available to encourage the transition to EV buses.4 In addition to such policy-based subsidies, private investment from both financial and strategic quarters has increased.  Market participants who take advantage of such funding earlier than their competitors have a forward seat to position themselves as leaders.

You kids pipe down back there, I’ve got my eyes on a pile of cash up ahead!

Government funding incentives for electrification are available for new EV buses and for repowering existing vehicles.5 Notably, the Infrastructure Investment and Jobs Act committed $5 billion over five years to replace existing diesel buses with EV buses. Additionally, the Diesel Emissions Reduction Act provided $18.7 million in rebates for fiscal year 2021 through an ongoing program.

In 2021, New York City announced its commitment to transition school buses to electric by 2035.  Toward that goal, the New York Truck Voucher Incentive Program provides vouchers to eligible fleets towards electric conversions and covers up to 80% of those associated costs.6  California’s School Bus Replacement Program had already set aside over $94 million, available to districts, counties, and joint power authorities, to support replacing diesel buses with EVs, and the state’s proposed budget for 2022-23 includes a $1.5 billion grant program to support purchase of EV buses and charging stations.

While substantial growth in EV bus sales will continue in the years ahead, it will be important to keep an eye out for renewal, increase or sunset of these significant subsidies.

Market Players and Market Trends, OEMs, and Retrofitters

The U.S is a leader in EV school bus production:  two of the largest manufacturers, Blue Bird and Thomas Built (part of Daimler Truck North America), are located domestically, and Lion Electric (based in Canada) expects to begin delivering vehicles from a large facility in northern Illinois during the second half of 2022.  GM has teamed up with Lighting eMotors on a medium duty truck platform project that includes models prominent in many fleets, and Ford’s Super Duty lines of vehicles (which provide the platform for numerous vans and shuttle vehicles) pop up in its promotion of a broader electric future. Navistar’s IC Bus now features an electric version of its flagship CE series.

Additionally, companies are looking to a turn-key approach to deliver complete energy ecosystems, encompassing vehicles, charging infrastructure, financing, operations, maintenance, and energy optimization. In 2021, Highland Electric Transportation raised $253 million from Vision Ridge Partners, Fontinalis Partners (co-founded by Bill Ford) and existing investors to help accelerate its growth, premised on a turn-key fleet approach.7

Retrofitting is also on the move.  SEA Electric (SEA), a provider of electric commercial vehicles, recently partnered with Midwest Transit Equipment (MTE) to convert 10,000 existing school buses to EVs over the next five years.8 MTE will provide the frame for the school uses and SEA will provide its SEA-drive propulsion system to convert the buses to EV.9 In a major local project, Logan Bus Company announced its collaboration with AMPLY Power and Unique Electric Solutions (UES) to deploy New York City’s first Type-C (conventional) school bus.10

Industry followers should expect further collaborations, because simplifying the route to adopting an EV fleet makes it more likely EV products will reach customers.

Opportunities Going Forward

Over the long haul, EV buses should do well. Scaling up investments and competition on the production side should facilitate making fleet modernization more affordable for school districts while supporting profit margins for manufacturers. EVs aren’t leaving town, so manufacturers, fleet operators, school districts and municipalities will either get on board or risk being left at the curb.

Article By Michael J. Small and Samantha Ruppenthal at Foley & Lardner LLP

For more utilities and transportation legal news, click here to visit the National Law Review.

 

 

1https://shop.scholastic.com/parent-ecommerce/series-and-characters/magic-school-bus.html

2https://www.busboss.com/blog/having-an-electric-school-bus-fleet-is-easier-than-many-people-think

3https://thehill.com/opinion/energy-environment/570326-electric-school-bus-investments-could-drive-us-vehicle

4https://info.burnsmcd.com/white-paper/electrifying-the-nations-mass-transit-bus-fleets

5https://stnonline.com/partner-updates/electric-repower-the-cheaper-faster-and-easier-path-to-electric-buses/

6https://www1.nyc.gov/office-of-the-mayor/news/296-21/recovery-all-us-mayor-de-blasio-commits-100-electric-school-bus-fleet-2035

7https://www.bloomberg.com/press-releases/2021-02-16/highland-electric-transportation-raises-253-million-from-vision-ridge-partners-fontinalis-partners-and-existing-investors

8https://www.electrive.com/2021/12/07/sea-electric-to-convert-10k-us-school-buses/#:~:text=SEA%20Electric%20and%20Midwest%20Transit,become%20purely%20electric%20school%20buses.

9 Id.

10https://stnonline.com/news/new-york-city-deploys-first-type-c-electric-school-bus/

© 2022 Foley & Lardner LLP

Battle of the Benchmarks: Brent Crude Oil and West Texas Intermediate

Brent Crude Oil (Brent) and West Texas Intermediate (WTI) are the two leading global benchmark references for crude oil prices. Historically, the two have often tracked very closely to each other, without significant price variations. The exceptions were the period between 2011 and 2015, when prices for the two diverged dramatically, and, to a lesser extent, the period since mid-2017.

Figure 1: Spread between WTI and Brent Futures Prices
1/1/2000-2/28/2019

Source: Bloomberg

Note: The spread is calculated as the price of the WTI futures contract closest to expiry minus the Brent futures contract closest to expiry.
These prices are represented on Bloomberg as CL1 and CO1 respectively. CL1 trades on NYMEX and CO1 trades on ICE.

One reason for the first price divergence was the growth of U.S. crude production of WTI. Without the necessary infrastructure or regulatory certainty to facilitate crude exports from the U.S. and provide an outlet for this additional supply, WTI prices decreased relative to Brent, and trading volume in Brent futures contracts overtook WTI futures. Between 2015 and mid-2017, however, both infrastructure and regulatory changes in the U.S. led to price parity becoming the norm again.

In mid-2017, prices began to diverge a second time as increases in crude prices led to a renewal of production growth and also contributed to a destocking of U.S. crude inventory. These and other market factors have caused the battle for benchmark supremacy to heat up again. In this latest round, WTI futures volumes are overtaking Brent futures.

This article examines the evolution and relationship between these two benchmarks and what factors have impacted their prominence as a benchmark.

About the Benchmarks

While crude oil is not a homogeneous commodity, over time market conventions have gravitated towards the use of standardized benchmark reference rates. Each unique grade of crude is typically priced at a discount or premium relative to benchmark rates to reflect its quality, characteristics, and location. Benchmark grades tend to have certain characteristics, including large production volumes, stable market environments, and consistent quality characteristics.

Both Brent and WTI are considered higher-quality crudes relative to crude oil produced in the Middle East and Russia, and require less refining to produce useable petroleum products.[i] Both are often referred to as “light and sweet” because of their high quality.[ii]

Their futures trading volumes have grown substantially over time, averaging more than eight times the volume in 2018 than in 2000. This increase is often explained by price volatility, the use of commodities as inflation protection, and an expansion of tradable products to better meet the needs of market participants.[iii]

Figure 2: Monthly Volume Comparison of ICE Brent and CME WTI Futures
1/1/2010-2/28/2019

Figure 2

Source: Bloomberg

Note: The aggregate future volume is the sum of the volumes of all maturities of ICE Brent and CME WTI futures. All futures volumes are aggregated on a monthly basis.

These benchmarks, however, are distinct in many ways. Brent, a European crude benchmark, is based on production from multiple oilfields in the North Sea. WTI is a U.S. crude benchmark that reflects the land-based crude oil stored in Cushing, Oklahoma.

In addition, while both Brent and WTI have developed futures markets with high volumes and many participants, Brent trades mainly on the Intercontinental Exchange (ICE) and WTI trades mainly on the CME Group (CME).

Surge of U.S. Crude Gives Brent the Edge

Between 2010 and 2018, extraction from shale reserves almost doubled the overall production of crude oil in the U.S. This growth was driven by new technological advancements that enabled horizontal drilling and fracking, coupled with historically high crude prices that led to massive infrastructure investments. Most of the new production came from PADD 3, comprising states in the Gulf Coast (see Appendices A and B). Expanded production resulted in increased supply and inventory of domestic oil in Cushing, Oklahoma, the main storage and pipeline hub for U.S. crude.

Figure 3: Total Quarterly Production of Crude Oil in North Sea and United States[iv]
Q1 2010-Q4 2018

Figure 3 Total

Source: Dow Jones; Reuters News; U.S. Energy Information Administration

Note: The Seaway pipeline began pumping oil from Cushing, Oklahoma, to Houston, Texas, from May 19, 2012, to reverse the direction of the oil flow. The reversed service line had an initial capacity of 150,000 bpd and increased to 400,000 bpd in January 2013 and 850,000 bpd in July 2014.

Until 2010, WTI generally traded at a small premium over Brent, due in part to its lighter and sweeter characteristics. Given the increasing supply of U.S. crude, however, WTI prices declined relative to Brent, reaching a discount of more than $27 in October 2011.

WTI Catches Up

Two significant events helped to reverse the price disparity between WTI and Brent. The first was an investment in infrastructure to bring the oil to market.

Cushing, Oklahoma, is landlocked and inaccessible by tanker or barge, and pipelines are key to moving crude. When U.S. crude oil production increased rapidly, the existing pipeline was positioned to pipe crude into, but not out of, Cushing. In May 2012, Seaway Crude Pipeline Company LLC reversed the flow of the Seaway pipeline in order to pipe crude from Cushing to the Gulf Coast. When it reached full capacity in January 2013, the Seaway pipeline began moving about 400,000 bpd of crude oil to Texas. A twin (loop) of the pipeline, designed to run parallel to the existing line, was built and doubled the transportation capacity of crude oil to 850,000 bpd starting in July 2014.[v] An additional 100,000 bpd expansion is scheduled to come online in the first half of 2019.[vi]

The second event was a change in trade policy by the federal government. Traditionally, the U.S. government has tightly controlled oil exports. In fact, for 40 years, it had enforced a ban on exporting crude oil, allowing only minor exceptions such as oil shipped through the Trans-Alaska Pipeline, heavy oil from certain fields in California, and some small trades with Mexico.[vii]

At the end of 2015, the government lifted the ban on exporting crude oil from the continental U.S. Crude oil no longer had to be refined or lightly refined before exporting.[viii] Since the repeal of the ban, crude oil exports have risen, prompted by the increase in oil prices and by OPEC’s drive to cut production.[ix]

Figure 4: Weekly Levels of U.S. Crude Oil
1/1/2010-2/28/2019

Source: U.S. Energy Information Administration; Bloomberg

Note:

1. In the past, the U.S. Commerce Department had given export licenses for particular types of oil. Crude from Alaska’s Cook Inlet, oil passing through the Trans-Alaska Pipeline, oil shipped north for Canadian consumption, heavy oil from particular fields in California, some small trades with Mexico, and some exceptions for re-exporting foreign oil made up those exports.

2. The WTI futures is the price of the futures contract on WTI traded on CME closest to expiry (front month) on any given day. The Bloomberg ticker for this is CL1.

Another factor that expanded trading options for physical oil traders was the widening of the Panama Canal in mid-2016. The locks in the canal were widened to 180 feet from 109 feet and became accessible to new, larger ships called New Panamax that can carry more than twice as much cargo as previous ships crossing the canal (see Appendix C).[x] The waterway shrinks distances between refineries situated along the Gulf of Mexico and Asia to 9,000 miles from 16,000 miles, allowing U.S. producers to better compete in one of the world’s biggest oil-consuming markets.

On a global scale, the U.S. produces about 10 percent of the world’s crude oil, and exports less than 15 percent of its total production, making up less than 2 percent of global volumes.[xi] As of late January 2019, U.S. output had surpassed daily production in Russia and Saudi Arabia, making the U.S. the world’s leading oil producer. Although the U.S. export volumes may be small, they are important because they represent additional market options for the increasing production in the U.S., and U.S. production is able to quickly respond to global market factors and supply the marginal crude oil necessary to fill temporary fluctuations in demand.[xii] 

With WTI’s improved access to the Gulf Coast and with the export ban lifted, U.S. crude producers and exporters have more options regarding where and to whom to sell the crude.

New Supply Resumes Downward Price Pressure

Since mid-2017, the U.S. crude oil industry has witnessed a renewal in production growth. Production in Q4 2018 was 30 percent higher than Q2 2017 (see Figure 3). This growth was largely driven by an increase in crude oil prices from a range of $25-$55 a barrel between 2016 and H1 2017, to $60-$75 a barrel between the beginning of 2018 and the end of Q3 2018.

Additionally, as prices rose, crude oil kept in storage during the period of lower prices was destocked. In other words, it was no longer profitable to store oil because current prices exceeded the cost of storage and anticipated future prices. For a time, the futures forward curve shifted from contango to backwardation.[xiii]

Figure 5: Storage Capacity Utilization of U.S. Crude Oil
3/2011-9/2018

Storage Capacity

Source: U.S. Energy Information Administration

Note: Alternate Utilization Rate measures crude oil stores in tanks as well as crude oil in pipelines and in transit by rail in proportion to the sum of the tanks’ working storage capacity and stocks in transit.

These factors contributed to WTI prices decreasing relative to Brent prices and, as of early 2019, WTI was trading at close to a $10 discount to Brent. Interestingly, unlike the prior divergence in prices, growth in the trading of the WTI futures contract has outpaced that of Brent futures contracts (see Figure 2).

Figure 6: WTI and Brent Futures Prices
1/1/2003-2/28/2019

Source: Bloomberg

Note:

1. The WTI futures contract is the price of the futures contract on WTI traded on NYMEX closest to expiry (front month) on any given day.
The Brent futures contract is the price of the (front month) futures contract on Brent traded on ICE closest to expiry on any given day.
The Bloomberg tickers for these are CL1 and CO1 respectively.

2. The Seaway pipeline began pumping oil from Cushing, Oklahoma, to Houston, Texas, on May 19, 2012, to reverse the direction of the oil flow. The reversed service line had an initial capacity of 150,000 bpd and increased to 400,000 bpd in January 2013 and 850,000 bpd in July 2014.

Brent Crude Loses Steam

At the same time that U.S. crude production was booming, and trade policy was becoming less restrictive, production at the original oil fields that comprise Brent was steadily declining, including at the eponymous Brent oilfield (see Figure 3).

As production decreased, the composition of the benchmark changed with the gradual addition of new oil fields. These oilfields include Forties and Oseberg (added in 2002) and Ekofisk (added in 2007). Brent’s production base is thus referred to by the acronym of the four crude oil streams: BFOE. A fifth stream, Troll, was added in 2018, referred to as BFOE-T.[xiv]

The addition of Troll was an attempt to maintain a robust production base to support the Brent benchmark. In late 2018, S&P Global Platts (Platts) initiated an industry consultation on whether to make two additional changes to the benchmark. The first is to add Rotterdam cost-and-freight price (CIF) for the North Sea grades, which would likely double the volume of crude underlining the benchmark. The second is to include Russian, Central Asian, West African, or U.S. shale field crude in the Brent benchmark.[xv]

As each new field is added, the quality of oil and the ownership structure of what is considered Brent crude oil changes slightly (see Appendix D). The original Brent field oil has an API gravity of 37.5 degrees and a sulfur content of 0.4 percent, making it light and sweet.[xvi] However, the addition of the Forties field, which cannot be considered sweet as it exhibits sulfur content as high as 0.82 percent, has changed the oil quality of the benchmark.[xvii] Additionally, the Troll oil field has an API gravity of 35.9 degrees, too low to be considered light.[xviii]

Figure 7: Quality, Ownership, and Monthly Flow of Oil Fields Related to Brent Crude

Field

Quality

Ownership Partners

Monthly Flow
as of March 2019
(in ‘000 Barrels)

Year Added
to the Brent Benchmark
Brent

Light, Sweet

Shell 50.00%
ExxonMobil 50.00%

2,400

1975
Forties/Buzzard

Light,
Not Sweet

Forties:
Apache 97.14%
ExxonMobil 2.61%
Shell 0.25%
Buzzard:
Nexen 43.21%
Suncor 29.89%
Chrysaor 21.73%
Dyas: 4.70%
Oranje-Nassau Energy: 0.46%

11,400

2002
Oseberg

Light, Sweet

Equinor 49.30%
Petoro 33.60%
Total 14.70%
ConocoPhillips 2.40%

3,600

2002
Ekofisk

Light, Sweet

Total 39.90%
ConocoPhillips 35.11%
Vår 12.39%
Equinor 7.60%
Petoro 5.00%

6,600

2007
Troll

Not Light, Sweet

Petoro 56.00%
Equinor 30.58%
Shell 8.10%
Total 3.69%
ConocoPhillips 1.62%

5,400

2018

 

Source: Thomson Reuters Monthly Production Data; https://www.cmegroup.com/rulebook/NYMEX/; https://www.platts.com/IM.Platts.Content/MethodologyReferences/Methodolo… http://factpages.npd.no/factpages/; http://www.offshore-technology.com/projects/brentfieldnorthseaun/; https://www.offshore-technology.com/projects/forties-oil-field-north-sea… http://www.nexencnoocltd.com/en/Operations/Conventional/UKNorthSea/Buzza… http://www.offshore-technology.com/projects/forties-oilfield-a-timeline/; https://www.ineos.com/businesses/ineos-fps/business/forties-blend-quality/; http://www.reuters.com/article/us-oil-platts-idUSKBN13R1PH; https://www.offshore-technology.com/projects/buzzard/; https://www.norskpetroleum.no/en/facts/field/oseberg/; http://www.conocophillips.no/our-norway-operations/greater-ekofisk-area/; https://www.offshore-technology.com/projects/troll-phase-three-developme…

Note:

1. Crude oil is considered “light” if it has an API gravity of between 37 and 42 degrees. Crude oil is considered “sweet” if it is low in sulfur content (< 0.42% by weight). These definitions come from the CME Group’s NYMEX Rulebook, although other sources use different ranges to classify light crude and sweet crude. Crude oil that does not qualify as light according to this definition is labeled as “not light” and crude oil that does not qualify as sweet according to this definition is labeled as “not sweet.” Crude oil in these categories may be referred to as “heavy” or “sour” in other sources, or they may be referred to as “medium sulfur” or “medium weight” if they fall between a source’s definition of “sweet” and “sour” or “light” and “heavy.”

2. Ownership percentages rounded to two decimal places.

3. The Forties Blend, transported via the INEOS-operated Forties Pipeline System, is made up of crude oil from over 70 fields. Buzzard is broken out separately since it is the largest component field and its inclusion starting in 2007 “altered the hydrocarbon characteristics of the Blend.” See https://www.ineos.com/businesses/ineos-fps/business/forties-blend-quality/.

One function of a benchmark is to provide an easy reference for buyers and sellers to price the wide variety of crudes with an agreed-upon differential to the benchmark. The differential, however, is dependent on the quality of the benchmark both in terms of volume and consistent quality. The potentially changing nature of Brent crude oil quality could jeopardize its role as the leading benchmark in many pricing contracts.

BFOE-T constitutes around 1 percent of world crude production,[xix] and there is concern that it does not provide a solid enough base for the Brent spot market to perform efficiently. Market and trading participants have recognized this change, and trading of the main futures contract of WTI and Brent has reversed. WTI futures trading volume has risen rapidly on NYMEX and has surpassed Brent on ICE. In January 2019, 30.0 billion WTI futures contracts were traded on NYMEX, compared to 17.3 billion Brent futures contracts on ICE.

Brent’s Delivery Mechanism

The price and the cash settlement mechanism of Brent futures are tied directly to the BFOE forward market, whose prices are assessed and published by price reporting agencies (e.g., Platts). This forward market consists of contracts that can be traded up to three months ahead of delivery. The forward contract assessment reflects the outright price of a cargo with physical delivery during the specified contract month for Brent, Forties, Oseberg, Ekofisk, and Troll crudes.

The closest-to-delivery contract for crude from BFOE-T basins is the spot market known as Dated Brent. Unlike other spot markets, Dated Brent has an inherent “forward” component to the contracts. On any given day, the contracts are written for the assessment of crude 10 days to one month forward from the contract date.

To enhance hedging opportunities, Brent traders can use the contract-for-difference (CFD) market. CFDs are swap contracts that track the difference between Dated Brent and BFOE forwards and allow traders to cope with the basis risk between the physical market and the financial risk-management market.

On the appointed day of delivery, sellers in the market will always load the product that is cheapest to deliver within allowable specifications.[xx] The cheapest-to-deliver concept became more important in 2007 with the introduction of the Buzzard field into the Forties stream. Because Buzzard tends to have lower-quality crude than other basins, it often became the cheapest crude that would fulfill contractual obligations.

Several iterations of quality price de-escalators and premiums were introduced over the years to compensate buyers in the event of low-quality deliveries, or to incentivize sellers to deliver higher-quality crude. Currently, Platts publishes a de-escalator for Forties Blend monthly, and Quality Premiums for Oseberg and Ekofisk are published for the current and following month. As the supply of BFOE-T basins declines overtime, more crude streams may be added to the deliverable basket. This will imply ever more complex and more frequent premium and discount calculations, depending not only on quality specifications, but also on freight differentials.

Price Report Agencies

Given that physical oil is traded by a few industry participants over the counter instead of on an exchange, the industry benefits from the increased transparency that price-reporting agencies provide by publishing assessed prices of the physical oil. Industry participants commonly trade physical and derivative products by reference to the prices reported by agencies such as Platts, Argus, and ICIS.

The main price-reporting agency for physical oil is Platts, which reports daily prices for over 200 global crude oil markets.[xxi] In order to calculate these daily prices, Platts compiles bids, offers, and transactions data submitted by physical oil market participants throughout each day as part of the Market-on-Close (MOC) process.[xxii] The last 30 minutes are considered the MOC window, which is an assessment period that determines an end-of-day value by using all available data from the day. Platts requires that participants declare their intention to post bids or offers in the MOC window before a cutoff point in the afternoon, which is 30 minutes before the close of the market.

A concern for regulators is whether the benchmark prices could be distorted by market participants, given that reporting transactions is optional. In March 2012, the International Organization of Securities Commissions (IOSCO), an umbrella body of market regulators, issued a report raising questions of whether further regulation was necessary.[xxiii] Similarly, from 2013 to 2015, the European Commission launched an investigation into the potential manipulation of oil price benchmarks.[xxiv] While this investigation did not lead to any convictions or fines, the European Union issued updated Benchmark Regulations in mid-2016.[xxv]

Conclusion

The Brent and WTI crude oil benchmarks have long battled for supremacy, and each faces different challenges. Scrutiny over Brent’s falling production in the North Sea has long been a concern, and WTI faces scrutiny for being in a landlocked location.

The views expressed in this article are solely those of the authors, who are responsible for the content, and do not necessarily represent the views of Cornerstone Research.

Endnotes

[i] “Crude Oils Have Different Quality Characteristics,” Today in Energy, U.S. Energy Information Administration, July 16, 2012, https://www.eia.gov/todayinenergy/detail.php?id=7110; WTI is both slightly lighter (American Petroleum Index (API) gravity of 39.6 vs. 38.3 degrees) and sweeter (0.24% vs. 0.37% of sulfur) than its Brent counterpart.

[ii] WTI is both slightly lighter (API gravity of 39.6 vs. 38.3 degrees) and sweeter (0.24% vs. 0.37% of sulfur) than its Brent counterpart.

[iii] “What’s Driving Global Oil Volumes Right Now,” MarketVoice, March 10, 2017, https://marketvoice.fia.org/issues/2017-03/whats-driving-global-oil-volu….

[iv] Total volumes for the North Sea fields Brent, Forties, Oseberg, and Ekofisk for July 2015, December 2015, and December 2016 were calculated by multiplying production rates by days of the month. Total volumes for June 2011, September 2011, October 2011, November 2011, October 2014, June 2015, July 2015, December 2015, December 2016, October 2017, and November 2017 for which data were unavailable were averaged from the latest prior and next earliest months’ total volumes.

[v] “About Seaway,” Seaway Crude Pipeline Company, http://seawaypipeline.com/.

[vi] “Seaway Begins Open Season,” Seaway Crude Pipeline Company Press Release, December 21, 2018, https://seawaypipeline.com/news/20181221PressRelease.pdf.

[vii] “Why the U.S. Bans Crude Oil Exports: A Brief History,” International Business Times, March 20, 2014, http://www.ibtimes.com/why-us-bans-crude-oil-exports-brief-history-1562689.

[viii] “Why the U.S. Bans Crude Oil Exports: A Brief History,” International Business Times, March 20, 2014, http://www.ibtimes.com/why-us-bans-crude-oil-exports-brief-history-1562689.

[ix] “OPEC, Allies Get Back on Track with Oil Cuts,” Bloomberg, May 17, 2019, https://www.bloomberg.com/graphics/opec-production-targets/.

[x] “Expanded Panama Canal Reduces Travel Time for Shipments of U.S. LNG to Asian Markets,” Today in Energy, U.S. Energy Information Administration, June 30, 2016, http://www.eia.gov/todayinenergy/detail.cfm?id=26892.

[xi] “U.S. Crude Production,” U.S. Energy Information Administration, https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm; “U.S. Exports by Destination,” U.S. Energy Information Administration, https://www.eia.gov/dnav/pet/pet_move_expc_a_EPC0_EEX_mbblpd_a.htm. For global oil production, see “BP Statistical Review of World Energy,” BP, June 2018, https://www.bp.com/content/dam/bp/business-sites/en/global/corporate/pdf….

[xii] “U.S. Oil Exports Double, Reshaping Vast Global Markets,” Wall Street Journal, June 7, 2017, https://www.wsj.com/articles/u-s-oil-exports-double-reshaping-vast-globa….

[xiii] “CVR Refining Oil Storage Sale Comes as Cushing Inventories Near 4-Year Low,” S&P Global Market Intelligence, September 18, 2018, https://www.spglobal.com/marketintelligence/en/news-insights/trending/tb….

[xiv] “Another Type of Crude Oil to be Included in Calculation of the Brent Price Benchmark,” Today in Energy, U.S. Energy Information Administration, March 10, 2017, https://www.eia.gov/todayinenergy/detail.php?id=30292.

[xv] “Shell Says Russia Oil Must Be Considered for Brent Benchmark,” Bloomberg, May 10, 2017, https://www.bloomberg.com/news/articles/2017-05-10/shell-says-russia-s-o… “Brent Benchmark Set for Revamp with Oil from Around the World,” Bloomberg, September 23, 2018, https://www.bloomberg.com/news/articles/2018-09-24/brent-benchmark-set-f….

[xvi] “Riding the Wave: The Dated Brent Benchmark at 30 Years Old and Beyond,” Platts, February 2018, p. 5, https://www.platts.com/IM.Platts.Content/InsightAnalysis/IndustrySolutio….

[xvii] “Forties Blend,” ExxonMobil, November 26, 2018, http://corporate.exxonmobil.com/en/company/worldwide-operations/crude-oi….

[xviii] “Crude Oil Assays,” Equinor, https://www.statoil.com/en/what-we-do/crude-oil-and-condensate-assays.html.

[xix] “Another Type of Crude Oil to Be Included in Calculation of the Brent Price Benchmark,” Today in Energy, U.S. Energy Information Administration, March 10, 2017,  https://www.eia.gov/todayinenergy/detail.php?id=30292; Commodity Research Bureau, The CRB Commodity Yearbook (Barchart.com, 2018).

[xx] That is, the cargo whose quality specification is the lowest deliverable and thus would yield the lowest spot market price outside the futures delivery mechanism.

[xxi] “Platts Global Alert – Oil,” S&P Global Platts, https://www.spglobal.com/platts/en/products-services/oil/global-alert-oil.

[xxii] “An Introduction to Platts Market-On-Close Process in Petroleum,” Platts, https://www.platts.com/IM.Platts.Content/aboutplatts/mediacenter/PDF/int….

[xxiii] “Functioning and Oversight of Oil Price Reporting Agencies – Consultation Report,” OICU-IOSCO, Technical Committee of the International Organization of Securities Commissions, March 2012, https://www.iosco.org/library/pubdocs/pdf/IOSCOPD375.pdf.

[xxiv] “Oil Traders Spared as EU Commission Drops Price-Rigging Probe,” Bloomberg, December 7, 2015, https://www.bloomberg.com/news/articles/2015-12-07/oil-traders-spared-as….

[xxv] “Regulatory Engagement and Market Issues ­– European Benchmark Regulation,” S&P Global Platts, https://www.spglobal.com/platts/en/about-platts/regulatory-engagement.

Copyright ©2020 Cornerstone Research

For more on oil pricing see the National Law Review Environmental, Energy & Resources law section.

Historic Worldwide Deal Ends Oil Price War

Oil-producing nations around the world reached an unprecedented agreement over the weekend that will cut world oil output by nearly 10 percent in an effort to end the devastating price war waged worldwide this year over the price of oil. That price war had threatened to break the so-called OPEC+ alliance between members of the Organization of Petroleum Exporting Countries (OPEC), including Saudi Arabia and Iraq, and allied producer states such as Russia and Mexico; just a few weeks ago, that partnership appeared to be on life support.

But now, a deal has been struck between the OPEC+ nations and other leading producer nations, including the United States, Canada, and Brazil, under which OPEC+ nations will cut production by 9.7 million barrels a day, while the non-OPEC+ nations will consider, but have not committed to, further cuts in production. Talks had reportedly stalled at times over the last seven days, but the involvement of the non-OPEC+ nations in the agreement showed the lengths to which producer nations were willing to go to end the oil price war and is politically significant since nations like the United States have historically criticized OPEC+ production policies.

© Steptoe & Johnson PLLC. All Rights Reserved.

Predicting Old Man Winter and Energy Outlooks: Is it Anyone’s Guess?

Whether we have a strong winter impacts many things.  From our road conditions driving to work, the extent of demand for home heating fuels, how our livestock will fair, and our ski season (including vital tourist revenue that results from ski season), predicting the degree of the intensity of the winter season can be important.

But this year it looks like it could be anyone’s guess…some degree of certainty would be nice, as it can have a major impact on energy forecasts as well.  For example, natural gas and propane demand.

The U.S. Energy Information Administration (“EIA”) released its Short-Term Energy Outlook (“STEO”) earlier this month, which can be found here.  The October STEO contains a lot of interesting information, including, but not limited to, that the “EIA expects downward oil price pressure to emerge in the coming months as global oil inventories rise during the first half of 2020.”

However, what really caught my eye in the October STEO was the EIA’s prediction as to the upcoming winter.

In my neck of the woods, cattle ranchers are bracing for a big winter – folks are beefing up (pun intended) winter structures in their pastures to give their cows some protection from intense snow storms, and old timers are warning to push calving season later this year to avoid calves being born during the worst of the early spring snow storms.  Many people in my home state of Wyoming have already buttoned up their summer homes in the mountains and have had snowfall since the beginning of the month.  According to The Weather Channel article entitled, It’s a Record-Snowy Start For the Northern Rockies and Plains and Winter Is Still Over 2 Months Away, some areas have already been pounded by record-dumping snowstorms.

In fact, The Old Farmer’s Almanac similarly predicts in its winter 2019-2020 forecast, which can be found here, “below-normal winter temperatures” through most of the U.S. coupled with significant snowfall.  The 2020 Old Farmer’s Almanac predicts a “snow-verload” of “frequent snow events – from flurries to no fewer than seven big snowstorms coast to coast, including two in April for the Intermountain region west of the Rockies.”

The October STEO takes a different stance – The EIA forecast as to the winter fuels outlook is based upon a mild winter.  Indeed, the October STEO provides the following winter fuels outlook:

  • “The [EIA] forecasts that average household expenditures for all major home heating fuels will decrease this winter compared with the last.  This forecast largely reflects warmer expected winter temperatures compared with last winter.”

The National Oceanic and Atmospheric Administration (“NOAA”) also released the following prediction:  Winter Outlook: Warmer than average for many, wetter in the North, which forecasts “warmer-than-average temperatures…for much of the U.S. this winter.”  NOAA predicts that “[n]o part of the U.S. is favored to have below-average temperatures this winter.”

The Weather Channel seems to take the middle road in its forecast entitled, Winter 2019-20 Will Likely Be Warmer Than Average in Southern U.S. & Colder Than Average in Parts of Northern Tier, and also includes the following disclaimer: “Given some of the conflicting factors listed above, this forecast will likely change, so be sure to check back to weather.com for updates.”

What will this winter be like and what will the weather’s impact be on the domestic energy outlook?  It is anyone’s guess!

© Steptoe & Johnson PLLC. All Rights Reserved.

For more on the energy industry, see the National Law Review Environmental, Energy & Resources law page.

Climate Change and Trends in Global Finance

On December 12, French President Emmanuel Macron, joined by President of the World Bank Group, Jim Yong Kim and the Secretary-General of the United Nations, António Guterres, hosted the One Planet Summit highlighting public and private finance in support of climate action. The summit’s focus centered on addressing the fight against climate change and ensuring that climate issues are central to the finance sector.

The summit’s most notable event was perhaps the announcement that insurance giant Axa would be dumping investments in and ending insurance for controversial U.S. oil pipelines, quadrupling its divestment from coal businesses, and increasing its green investments fivefold by 2020. Axa’s plans echo those of BNP Paribas, who, in mid-October, announced that it would terminate business with companies whose principal activities involve exploration, distribution, marketing, or trading of oil and gas from shale or oil sands. The bank also ceased financing projects that are primarily involved in the transportation or export of oil and gas. These moves themselves follow controversy over the Dakota Access pipeline in the U.S. from mid-March that resulted in ING’s $2.5 billion divestment in the loan that financed the pipeline.

These measures prefigure what might be a more conspicuous trend of large institutional investors moving more rapidly away from fossil fuel investments and into green investments. In mid-December, the World Bank said it would end all financial support for oil and gas exploration by 2019. Around the same time, New York Governor Andrew Cuomo revealed a plan for the state’s common retirement fund, with over $200 billion in assets, to cease all new investments in entities with significant fossil-fuel related activities and to completely decarbonize its portfolio. Recently, HSBC pledged $100 billion to be spent on sustainable finance and investment over the next eight years in an effort to address climate change. Additionally, JP Morgan Chase committed $200 billion to similar clean-minded investments, Macquarie acquired the UK’s Green Investment Bank, and Deutsche Bank and Credit Agricole both made exits from coal lending. As the landscape of global finance shifts, it will be important to monitor how funds, banks, and insurers address the issues related to climate change.

 

©1994-2017 Mintz, Levin, Cohn, Ferris, Glovsky and Popeo, P.C. All Rights Reserved.

The UK 14th Onshore Oil and Gas Licensing Round

Andrews Kurth

At the end of July 2014, the UK government published application criteria and terms for the 14th onshore oil and gas licensing round. This will be key to the aspirations of would-be shale gas developers in the UK. Onshore licences are available in areas including the Bowland Shale in the north of England (where the British Geological Society estimates a potential gas-in-place resource of 1,329 trillion cubic feet (tcf) alone) and the Midland Valley in Scotland.

Applications for new licences under the 14th round can be made until 2:00 p.m. 28 October 2014. This is the first round of onshore licensing in the UK for six years, and the resultant final licence awards are expected to be announced in the next 12 to 18 months. The level of interest expressed in these new licences will be a good barometer of how the industry regards the steps which the UK government has been taking to promote the growth of shale gas in the UK.

Additionally, new model clauses for onshore licences have been issued in the Petroleum Licensing (Exploration and Production) (Landward Areas) Regulations 2014, which came into force on 17 July 2014. These model clauses are intended to promote unconventional oil and gas exploration and production and include several new provisions which are aimed at affording greater flexibility to licensees – these provisions relate to “drill or drop” elections, the term of the licence (with revised focus on extensions and retention areas) and splitting horizontal layers on surrenders.

The new model clauses recognise the different attributes of shale gas exploration and production programmes and that shale gas deposits typically have a much wider geographic footprint when compared to conventional oil and gas resources. Whilst greater flexibility is given to licensees under the new model clauses, there are also tighter controls over proposed project activities and timescales, with the intention of accelerating the outturns of planned exploration and production plans. 

The new model clauses are also intended to promote the findings of the recent Wood Review relating to maximising economic recovery.

There is also a new requirement for a detailed Environmental Awareness Statement (“EAS”) to be submitted with licence applications. The EAS is intended to demonstrate a licence applicant’s understanding of the environmental sensitivities relevant to the area proposed to be licensed. This requirement is intended to promote a successful interface with ecological sensitivities.

The UK government has taken a number of other steps to promote shale gas development in the UK, including introducing localised fiscal incentives to support the development of shale gas exploration pads. However, significant other issues still remain to be addressed by would-be shale gas developers, including obtaining planning permission to drill and hydraulically fracture test wells and managing often vociferous local public opposition to shale gas development. We have previously considered how UK onshore shale gas developments might be structured (see Notes From The Field – Issues 3 and 6).

Many challenges still lie ahead. Oil & Gas UK, the trade association that represents the interests of the UK’s offshore oil and gas industry, has given a cautious welcome to these new developments:

“There are a number of synergies between the offshore oil and gas industry and the onshore sector. Many of the techniques and some of the services required to recover land based unconventional shale gas already exist in the offshore oil and gas sector and should be readily transferable. There is scope for making these learnings and expertise from the offshore sector quickly transferable to operators developing onshore oil and gas resources. The new Oil and Gas Authority, which will govern both onshore and offshore industries, should ensure consistency of approach wherever applicable.”

ARTICLE BY

Peter Roberts
 
OF 
Andrews Kurth

Texas Supreme Court Clarifies Royalty Calculations For Enhanced Oil Recovery

steptoe-johnsonlogo

In French v. Occidental Permian, Ltd., the Texas Supreme Court clarified royalty calculations for enhanced oil recovery.  The Court:

  1. Rejected a royalty owners’ claim that royalties on casinghead gas should be determined as if the injected carbon dioxide (CO2) was not present
  2. Held that, under the applicable leases and Unitization Agreement, the costs of removing CO2 from the gas were post-production expenses that royalty owners must share with the working interest owner

In the opinion, the Court emphasized the importance of efficient production of oil and gas and the prevention of waste.

Background

The Plaintiffs-Appellants, Marcia Fuller French and others (“French”), were lessors on two different oil and gas leases.  Both lease royalty provisions provided that the casinghead gas royalty was net of post-production expenses, but not production expenses.  The Defendant-Appellee, Occidental Permian Ltd. (“Oxy”) owned a working interest.  The parties had entered into a Unitization Agreement to allow secondary recovery operations.

Oxy began injecting wells on these leases with CO2 in 2001 in order boost oil production when waterflooding became less effective.  As a result, the wells produced natural gas that was about 85% CO2.  Although Oxy could reinject the entire casinghead gas stream, Oxy had the gas treated off site to remove the CO2.   It sold the resulting gas and had the extracted CO2 sent back to the well to be reinjected.  Oxy paid royalties on the gas after it was treated and deducted the treatment costs from French’s royalties.

French sued arguing that, except for the removal of contaminants and the extraction of NGL, the costs of processing the casinghead gas (including transportation costs) were production costs that should be borne solely by Oxy.  Conversely, Oxy argued the CO2 removal was necessary to render the gas stream marketable.  At trial, the Court agreed with French and awarded her $10,074,262.33 in underpaid royalties and entered a declaratory judgment defining Oxy’s ongoing royalty obligations.  The court of appeals reversed with a focus on the damages calculations, but did not reach a decision on whether the cost of separating the CO2 from the casinghead gas was a production expense.

Supreme Court’s Decision

The Court examined the parties’ agreements noting that French consented to the injection of extraneous substances into the oil reservoir and gave Oxy the right and discretion to decide whether to reinject or process the casinghead gas.  The Court further pointed out the Agreement provided that the royalty owners agreed to forego royalties on any unitized substances used in the recovery process.  The Court found that French benefited from that decision and therefore must share in the cost of the CO2 removal.  The question then became whether the CO2 processing was a production or post-production cost.

French argued that the CO2 separation was akin to the removal of water from oil, which Oxy treated as a production cost.  The Court, however, found that oil and water are “immiscible” and separation of the two is a relatively simple process, unlike CO2 and gas separation, which requires special technology.  Water separation is necessary for reinjection into the reservoir and to make the oil marketable.  Conversely, CO2 separation is not necessary for continued production of oil.  The Court then noted that Oxy was not required to reinject the casinghead gas.  Therefore, based on the parties’ agreements, “French, having given Oxy the right and discretion to decide whether to reinject or process the casinghead gas, and having benefited from that decision, must share in the cost of the CO2removal.”  Id. at 7.

Conclusion

The Court indirectly emphasized efficient production of oil and gas and prevention of waste.  The gas processing was economically beneficial to both French and Oxy.  The CO2 separation increased the value of the stream to both Oxy and French by allowing sale of the extracted NGLs and allowing reinjection of more than 10% of the gas produced directly back into the field.  Because French received the benefit of Oxy’s decision, it had to share in the cost.

This opinion is an important reminder to carefully negotiate and agree to terms in all agreements.  It is a further reminder to proceed in an efficient and economic manner.

ARTICLE BY:

Christina A. Denmark
Of:
Steptoe & Johnson PLLC

Commerce Department Rulings Spur Oil Export Battle

Covington BUrling Law Firm

As reported in our blog post of last week, the Commerce Department Bureau of Industry and Security (“BIS”) recently determined in two private classifications that lease condensate — a type of stabilized and distilled light crude oil — is not subject to the United States’ broad ban on crude oil exports.  BIS has for years defined “crude oil” in its regulations as “a mixture of hydrocarbons that existed in liquid phase in underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and which has not been processed through a crude oil distillation tower.”   Although the regulations state that this definition includes lease condensate, BIS appears to have determined that lease condensate that has been distilled is a refined petroleum product that is not subject to the broad ban on crude oil exports from the United States.

While BIS claims that there has been “no change in policy on crude oil exports,” the recent determinations have spurred the debate over whether the U.S. should change its position on crude oil exports.  In particular, Senators Robert Menendez (D-NJ) and Edward Markey (D-Mass.) — who have been vocal opponents of lifting the ban on crude oil exports — wrote a letter to Commerce Secretary Priztker alleging that BIS may have impermissibly approved the exports of lease condensate and demanding copies of the two determinations and information on the legal rationale for approving such exports by July 14, 2014.  Senators Markey and Menendez argue that allowing exports of crude oil would increase reliance on foreign oil and cause domestic gas prices to rise.  However, with U.S. crude oil production surging as a result of the advancements in hydrofracking technology, Senators Lisa Murkowski and Mary Landrieu have championed the effort to reconsider the ban on crude oil exports, which has been in place since the Arab oil embargo and global energy supply shortages of the 1970s.  In particular, Senator Murkowski has issued a report calling for a “renovation” of U.S. energy export policy, which includes an April 2014 white paper in advocating for condensate exports.

While some view BIS’ approval of condensate exports as a step towards a greater liberalization in crude oil export policy, financial analysts such as Morgan Stanley are not bullish on any significant changes occurring before this years’ mid-term elections.  Moreover, recent reports indicate that the White House may not have been aware that BIS was planning to issue such determinations, and therefore this may not represent a conscious effort on the part of the Obama Administration to change crude oil export policy.  Indeed, Secretary Pritzker has confirmed publicly that the rulings were not a change in policy.  However, the Secretary also said that “it’s a mistake to think there isn’t serious conversation going on within the administration about what we should do,” and that the issue of energy exports overall should be “examined holistically from an economic, strategic, and diplomatic standpoint.”  These statements suggest that the Administration is not backing down from the condensate rulings, and is considering the broader policy issues involved in allowing exports of other oil products.

Article By:

E. Donald Elliott
Peter Flanagan
Sarah Liebschutz
Of:
Covington & Burling LLP