Fashion Sustainability and Social Accountability Act Proposed in New York

Happy New Year (are we still saying that?) from the Global Supply Chain Law Blog!  In our ever-evolving society, the fashion industry has taken new heights.  And with those heights, the industry is on pace to account for more than a quarter of the world’s carbon budget, according to the New Standard Institute.   Indeed, the group indicates that apparel and footwear are responsible for roughly 4-8.6% of global greenhouse gas emissions.  You may be wondering, “but how?”  Well after that sweater you bought last year (or even last month!) goes out of style, you may donate it.   According to CBS, some of those donations go overseas to Ghana, for example, to be sold.  The unsold clothes, however, end up as landfills creating an environmental nightmare.

As a result and in an effort to create more regulation, New York is taking action with respect to the environmental nightmare. Earlier this year, the New York legislator proposed a bill—the Fashion sustainability and social accountability act, which would amend the general business law, requiring fashion retail sellers and manufacturers to disclose environmental and social due diligence and policies.

Specifically, every fashion retail seller and fashion manufacturer doing business in the State of New York and having annual global gross revenues that exceed $100 million dollars must disclose its:

  1. environmental and social due diligence[1] policies,
  2. processes and outcomes, including significant real or potential negative environmental and social impacts, and
  3. targets for impact reductions, implementation, improvement and compliance on an annual basis.

The required disclosures would include supply chain mapping of at least 50% of suppliers (which the retail seller or manufacturer could choose) by volume across all tiers of production, a sustainability report, independently verified greenhouse gas reporting, volume of production displaced with recycled materials, and median wages of workers of suppliers compared with local minimum wage, to name a few.

All disclosures must be posted on the retail or manufacturer’s website within a year of enactment.  Enforcement of the bill would fall to the state’s attorney general, who would publish a report listing the fashion retail sellers and manufactures who are out of compliance with the act. Public shaming would not be the only punishment, however.  Retailers and manufacturers who fail to comply may be fined up to 2% of annual revenues of $450 million or more.  The money from the fines will be deposited into a community benefit fund, which will be used for environmental benefit projects that directly and verifiably benefit environmental justice communities.

In short, if the Fashion sustainability and social accountability act is enacted into law, fashion retailers and manufactures will be held accountable for environmental and social impacts stemming from their supply chain and production of apparel and shoes.  According to Vogue, “proponents say the bill will make history” as it could “shift how the fashion industry operates globally.” Thus, stay tuned as we will be tracking the legislation closely and will provide real time updates!

[1] “Due diligence” shall mean the process companies should carry  out to  identify,  prevent, mitigate and account or how they address actual and potential adverse impacts in  their  own  operations,  their  supply chain  and other Business relationships, as recommended in the Organisation for Economic Co-operation and Development Guidelines  for  Multinational  Enterprises,  the  Organisation  for Economic  Co-Operation and Development Due Diligence Guidance for Responsible Business Conduct  and United Nations Guiding Principles for Business and Human Rights.

© Copyright 2022 Squire Patton Boggs (US) LLP
For more articles on sustainability, visit the NLR Environmental, Energy & Resources type of law page.

A Hitchhiker’s Guide to What’s New in All Appropriate Inquiries

ASTM (American Society for Testing and Materials) due diligence standards have been updated to address environmental conditions not widely recognized in 2013 but EPA’s “all appropriate inquiry” regulations have yet to conform.

ASTM International (ASTM) issued its seventh version of Environmental Site Assessment (ESA) standards, E1527-21, on Nov. 1, 2021. These ASTM standards provide the leading source of guidance on minimum standards for Phase I ESAs for commercial and industrial property acquisitions. While ASTM E1527-21 improves upon the predecessor E1527-13, the US Environmental Protection Agency’s (EPA) “all appropriate inquiry” regulations (40 CFR § 312.11(b)) currently codify E1527-13 as setting the appropriate due diligence standard. As a matter of course, EPA is expected to amend its regulations to replace the reference to E1527-13 with a reference to E1527-21. However, until EPA amends its rules, buyers should recognize that the improved commercial standard for due diligence is based on E1527-21, but the regulatory safe harbor for complying with “all appropriate inquiry” standards for purposes of meeting EPA requirements remains E1527-13.

The changes in E1527-21 make it more stringent than E1527-13 and make E1527-13 insufficient for current transactions. Because rigorous ESAs provide important pre-acquisition business information, as well as statutory liability protection, we recommend, until EPA updates its Section 312 regulations, that purchasers immediately require that ESAs be performed to meet both E1527-13 and E1527-21 requirements. And following such EPA rulemaking, buyers should require ESAs meet E1527-21 requirements (presuming that is the outcome of the rulemaking).

E1527-21 identifies new requirements to be addressed in Phase I ESAs, including the following:

  • Enhanced research into the history of both the subject and adjoining properties.
  • Enhanced site recon investigation.
  • Definition changes to clarify what is or is not a recognized environmental condition (REC). For instance, a closure of an underground storage tank site may not have been remediated in the past to current regulatory standards. So there is now a requirement to look beyond, for example, a prior No Further Action letter. This is now a REC requiring further due diligence analysis.
  • Examples of RECs, such as poorly stacked drums and bulging tanks, are provided in new Appendix X.4.
  • Clarification of property use limitations and significant data gaps, which respectively may impair future site use or render an assessment’s findings of no RECs questionable.
  • Clarification on when the shelf life of a Phase I ESA commences, e.g., with an early record review component (or after a timely update) as opposed to using the final report date of the ESA.
  • Caveats about emerging issues like PFAS. See “Not So PFAS,” National Law Review (Nov. 2, 2021).
  • Clarification that the user is responsible for identifying environmental liens or land use or property use restrictions in a title search going back to 1980.

The environmental professional remains responsible for reporting to users on title search information and for finding institutional or engineering control records.

A systemic flaw in the E1527 standard is that it treats compliance issues like stepchildren, or not at all, by relying on users to add non-scope items such as wetland, air, water, and waste permit compliance. While this absence may be prudent for commercial properties and “green fields,” industrial properties require more. Compliance audits, including air, water, and waste compliance review, are needed for them. Unfortunately, the ASTM standard for those audits is only consultant process oriented (see ASTM E2107-20) and not sufficiently detailed, in our opinion.

However, the new E1527-21 standard will produce more conservative ESAs, perhaps increasing the cost of closing or raising additional cleanup concerns.

© 2022 Jones Walker LLP

Article By Robert Holden and Stanley A. Millan of Jones Walker LLP

For more articles on the ATSM, visit the NLR Environmental, Energy & Resources section.

EPA agreement with Kennedy Center protects water quality of Potomac River, Chesapeake Bay

PHILADELPHIA – The John F. Kennedy Center for the Performing Arts in Washington, D.C. has settled alleged Clean Water Act violations at its facility in Washington, D.C., the U.S. Environmental Protection Agency announced today.

The Kennedy Center, located at 2700 F St NW, has a Clean Water Act permit regulating its discharges of condenser cooling water from the facility’s air conditioning system into the Potomac River, which is part of the Chesapeake Bay watershed.

This settlement addresses alleged violations of temperature and pH discharge permit limits required under the Kennedy Center’s Clean Water Act permit. EPA also cited the Kennedy Center for failing to timely submit monitoring reports and failing to submit pH influent data. Additionally, the agreement addresses alleged violations identified by the District of Columbia’s Department of Energy and Environment during a prior inspection of the facility.

As part of the settlement, the Kennedy Center is required to submit a compliance implementation plan. The Kennedy Center has certified that it is now in compliance with permit requirements.

This agreement is part of EPA’s National Compliance Initiative: Reducing Significant Non-Compliance with National Pollutant Discharge Elimination System (NPDES) Permits. For more information about the Clean Water Act permit program, visit www.epa.gov/npdes.

Read this article in its original. form here.

© Copyright 2021 United States Environmental Protection Agency

Article by the EPA

Read more about the Clean Water Act in the NLR section Energy, Climate, and Environmental Law News.

Surprise! President Trump Nominates Democrat and Republican to FERC

On July 27, 2020, President Trump nominated two candidates to the Federal Energy Regulatory Commission (FERC), securing a Republican majority on the Commission through June 2021 while also ensuring a continued quorum.

Trump nominated Allison Clements, the Democrats’ top pick, alongside Republican Mark C. Christie. Clements currently serves as founder and president of Goodgrid, LLC, an energy policy and strategy consulting firm. She previously worked for over a decade at the Natural Resources Defense Council, and spent two years as director of the clean energy markets program at the Energy Foundation. Christie currently serves as chairman of the Virginia State Corporation Commission, having served for 16 years on the Virginia board that oversees utilities.

FERC is a five-member agency that should have no more than three members of any one party. For much of the past year it has been operating with three Republicans and one Democrat. FERC’s newest commissioner, James Danly, was confirmed in March despite requests from Democrats to pair his nomination with Clements. Clements would fill the seat left vacant by Commissioner Cheryl LaFleur in August 2019. If confirmed, Christie will take the seat of Republican Commissioner Bernard McNamee, whose tenure expired in June but who plans to stay on until his replacement is seated.

Republican Chairman Chatterjee has announced that he will remain on the Commission until the end of his term, which expires June 2021, although the next President will determine if he continues to serve as chairman. Trump’s appointment of Christie, paired with Chairman Chatterjee’s intention to fulfill his term, could secure a Republican-held Commission for the first months of a Biden presidency in the event the Democratic nominee is successful in November.


©2020 Pierce Atwood LLP. All rights reserved.

DOER Finalizes SMART Program Emergency Regulations

The Department of Energy Resources (DOER) has finished the required Solar Massachusetts Renewable Target (SMART) Program 400MW review and emergency rulemaking and published its final regulations. Several revisions and adjustments have been made to the final regulations, including an extension to the COVID-19 extension for new applications received through December 31, 2020.

Revisions have been made to previously published land-use exceptions. Projects that meet the below criteria will now be assessed under the former land-use regulations:

  • Have applied for the Interconnection Service Agreement (ISA) 135 business days prior to April 15, 2020, or have obtained a fully executed ISA by October 15, 2020; and
  • Have obtained a sufficient interest in real estate or other contractual rights to construct the Solar Tariff Generation Unit at the location specified in the ISA as of April 15, 2020.

Additionally, the DOER distinguished eligible land use between projects qualifying for capacity as part of the original 1600MW versus projects qualifying under the new 1600MW. Projects qualifying under the original 1600MW will be eligible for the SMART Program even if located on land designated as Critical Natural Landscape, while projects qualifying under the new 1600MW will be ineligible if the project is sited in a Priority Habitat, Core Habitat, or Critical Natural Landscape.

The final regulations also allow for single-axis trackers to be eligible for the Tracker Adder, and behind-the-meter systems to receive Alternative On-Bill Credits.

The DOER also made modifications to the Statement of Qualification Reservation Period Guideline. In addition to continuing the COVID-19 extension for new applications, the DOER has done the following:

  • Eliminated the requirement that projects obtaining an indefinite extension, pending the authorization to interconnect, must submit a claim within 10 business days of receiving the authorization to interconnect;
  • Granted eligible Public Entity Off-taker Adder Solar Tariff Generation Units an initial Reservation Period of 18 months;
  • Clarified that projects qualified as Community Shared Solar that do not submit a claim with the CSS Adder will have their base compensation rate decreased to the value in the lowest available Capacity Block, but will not be at risk of losing their Statement of Qualification outright: and
  • Established a process by which DOER will queue project applications if there is a rush of applications submitted following the issuance of ISAs by a Distribution Company upon the completion of an ASO study.

Several other Guidelines related to the SMART Program are still being revised, and the DOER is expected to release these updates in the coming weeks. Publication of the regulations is just the beginning phase for resuming the SMART Program. Changes to the regulations that affect the tariff will now need to be implemented into each Electric Distribution Companies’ tariffs and undergo administrative review of the Department of Public Utilities.


© 2020 SHERIN AND LODGEN LLP

For more on solar renewable energy, see the National Law Review Environmental, Energy & Resources law section.

COVID-19: IRS Extends Production Tax Credit/Investment Tax Credit Safe Harbors

On May 27, 2020, the IRS issued Notice 2020-41, which responds to industry-wide supply chain disruptions due to the COVID-19 pandemic by giving renewable energy developers additional time to complete their projects. Most importantly, the Notice extends two safe harbors applicable to the renewable energy production tax credit (PTC) and investment tax credit (ITC).

First, the “Continuity Safe Harbor” is extended from four years to five years for projects that began construction in 2016 or 2017. Developers that put the project in service by the end of the fifth calendar year after the year construction began will be deemed to meet the continuous construction requirement.

Second, relief is provided for developers that intend to meet the beginning construction requirement by incurring 5% of project costs, i.e., by making payments for services or property they reasonably expected to receive within 3½ months (a/k/a the 3½ Month Rule). Developers that pay for services or property on or after September 16, 2019 and actually receive the services or property by October 15, 2020, will be deemed to satisfy the 3½ Month Rule.

This relief is available to developers of wind, solar, biomass, geothermal, landfill gas, trash, hydropower, fuel cells, microturbines, and combined heat and power systems.


©2020 Pierce Atwood LLP. All rights reserved.

For more on IRS Safe Harbors, see the National Law Review Tax Law section.

Declaring National Emergency, President Trump Orders Restrictions on Electrical Equipment Supplied By “Foreign Adversaries”

In an Executive Order issued on May 1, 2020, President Trump declared that the unrestricted supply of electrical equipment from foreign countries represents an “unusual and extraordinary threat to the national security, foreign policy, and economy of the United States” because foreign adversaries may use such equipment to sabotage the nation’s electric power supply. While the scope of the order will not be clear until rules to carry it out are put in place, the order could prove disruptive to the supply chains for substations, transformers, and other equipment essential to operation of the nation’s electric power system, as well as to a new generation of “smart grid” devices that are transforming the electric grid, especially for devices that are manufactured in China.

The vulnerability of the electric system to malicious software and other threats embedded in equipment or components manufactured in the territory of hostile powers has long been recognized as a potential problem. In fact, the North American Electric Reliability Corporation, the entity responsible for promulgating and enforcing mandatory electric reliability standards, has developed a reliability standard (CIP-013-1) governing “Supply Chain Risk Management,” although the effective date for the standard was recently delayed by the Federal Energy Regulatory Commission due to the COVID-19 crisis.

In contrast to CIP-013-1, which requires each entity subject to the standard to develop its own plan for ensuring that relevant supply chains are free from cybersecurity risks, the new Executive Order contemplates a top-down approach, in which certain “foreign adversaries” would be identified and imports from those “adversaries” would be prohibited, although transactions with certain vendors would be allowed if they are on a “pre-approval” list. Notably, the Executive Order applies “notwithstanding any contract entered into or any license or permit granted prior to the date of this order” and authorizes the Secretary of Energy to act against “pending transactions” that might violate the order. Hence, the Executive Order could be applied retroactively, particularly to transactions that are now in process.

This aspect of the Executive Order is particularly troubling because it is likely to be at least several months before the exact reach of the Order is known. The Order directs the Secretary of Energy, in cooperation with other federal departments, to promulgate rules carrying out the Executive Order within 150 days. It is likely that the list of “foreign adversaries” will include China, which is an important link in the supply chain for many companies, as well as Russia, Iran, and North Korea. But that remains an unknown, as does the list of suppliers that might be included on the pre-approved list. The Executive Order is limited to the “bulk electric system”—high voltage transmission lines, substations, and related equipment – but contains a provision that could expand its reach to electric distribution systems, an area generally left to state regulation, based on recommendations from a security task force to be formed under the Executive Order.

The Executive Order creates new and potentially serious regulatory, contractual, and supply chain management issues for companies engaged in operation of the bulk electric system, in the manufacture of equipment necessary for operating the bulk electric system, and for emerging “smart grid” technologies that promise to improve the operation and efficiency of the bulk electric system.


© 2020 Beveridge & Diamond PC

For more on America’s electric infrastructure, see the National Law Review Environmental, Energy & Resource law section.

Northeast State Solar Programs in Light of COVID-19

COVID-19 is impacting industries across the globe and clean energy is no exception. As the pandemic continues to influence economic relief efforts at both the state and federal level, states are beginning to offer specific forms of relief through their incentive programs.

Additionally, electric distribution companies in each state have declared COVID-19 a force majeure event, allowing extensions to interconnection milestones and in some cases payment schedules. Below are summaries of the specific relief efforts being offered by some states, and more details regarding electric distribution companies’ declaration of a force majeure event.

Massachusetts

The Massachusetts Department of Energy Resources (“DOER”) filed emergency regulations with the Secretary of State following its regulatory 400MW review of the Solar Massachusetts Renewable Target (“SMART”) Program on April 14, 2020. Among the regulations is a blanket extension of six months to all Solar Tariff Generation Units, including any projects that submit their applications before July 1, 2020, due to the ongoing impacts of COVID-19. More details are provided in the DOER’s Statement of Qualification Guideline.

The Massachusetts Department of Public Utilities has also developed a webpage with information and resources specific to COVID-19. The website includes information on the impacts of the electric distribution companies’ respective declarations of COVID-19 as a force majeure event.

New York

The New York State Energy and Environment agencies wrote a letter to the clean energy industry on April 1, 2020, expressing support for the clean energy industry, particularly as construction has been impacted by COVID-19. The agencies announced in the letter that they are seeking input from clean energy industry stakeholders so that the agencies and the industry can work together to form creative solutions. The letter is found on NYSERDA’s COVID-19 page.

Connecticut

In Connecticut, the Department of Energy and Environmental Protection (“DEEP”) is coordinating with governmental offices and stakeholders to offer webinars for clean energy contractors with information about available state and federal aid. Please check in with CT DEEP to find out more information on these offerings.

Maine

The Governor’s Energy Office (GEO) released a statement that the GEO is working with the Maine Public Utilities Commission (PUC) and clean energy stakeholders to answer questions and concerns that are related to COVID-19. Stakeholders that have questions and concerns should contact the GEO for further information.

Electric Distribution Companies’ Force Majeure Declaration

Several electric distribution companies have notified state’s public utilities commissions that COVID-19 is a force majeure event. By declaring a force majeure event, the electric distribution companies have allowed extensions to project milestone dates and in some cases interconnection payments. Electric distribution companies that have not formally declared COVID-19 a force majeure event have waived late fees and extended payment timelines. Individual projects should check in with the electric distribution company specific to the project to confirm how theirs may be impacted.


 

 

© 2020 SHERIN AND LODGEN LLP
ARTICLE BY Tanya M. Larrabee at Sherin and Lodgen LLP, Amy L. Hahn also contributed.
For more on renewable energy programs, see the National Law Review Environmental, Energy & Resources law section.

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.


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