November 2019 Exclusive Story
Ruling Preserves Industry’s Ability To Employ Independent Contractors
MARINA, CA.–The U.S. Bureau of Land Management has announced plans to open 722,000 federal acres in California for oil and gas leasing and development. The announcement came from BLM’s Central Coast Field Office and covers acreage primarily in California’s Fresno, Monterey and San Benito counties. However, anti-development groups are suing to stop the move.
BLM has approved a resource management plan amendment for oil and gas leasing development to make 680,000 acres of federal mineral estate available for leasing with controlled surface use stipulations and another 42,000 acres available for leasing with no surface occupancy requirements.
The California Independent Petroleum Association says the bureau approved the RMP without modification after extensive environmental analysis, considering public comments, and applying pertinent federal laws and policies.
The announcement has drawn fire from California policymakers, and the state already has passed a law prohibiting any state agency from leasing state lands for oil and gas pipelines or infrastructure (see story page 28). Moreover, the Sierra Club and the Center for Biological Diversity filed a lawsuit against BLM at the end of October, published reports indicate, with the lawsuit claiming “Defendants failed to consider meaningful alternatives to the plan amendment, failed to analyze and disclose the environmental impacts and denied the public the opportunity to comment on its environmental analysis as the law requires.”
BLM notes that an additional 67,500 acres of federal minerals are closed to leasing and development, including designated Wilderness areas, Wilderness study areas and national monuments. The bureau says the plan also supports recovery of threatened and endangered plants and animals in the Ciervo Panoche Natural Area by protecting core populations from surface disturbance.
CIPA says lease offerings have been on hold since an anti-development lawsuit filed during the Obama administration. Although the area’s geology is unsuitable for hydraulic fracturing, CIPA says, activists mischaracterized its use in the area, prompting BLM to sign a settlement that required it to complete a supplemental environmental impact statement.
According to BLM, its decision also authorizes it to issue, with controlled surface use stipulations, 14 previously litigated oil and gas leases in Monterey and San Benito counties because the EIS addresses issues identified by the District Court in litigation and fulfills BLM’s obligations under the settlement.
Media reports cite BLM Central Coast Field Office Manager Ben Blom saying that the new lease offerings follow President Donald Trump’s balanced approach to public lands. “This decision supports the administration’s priority of promoting environmentally responsible energy development, while creating jobs and providing economic opportunities for local communities. It strikes a balance between resource conservation and energy development consistent with BLM’s mission for managing the lands for multiple use and sustained yield,” Blom is quoted.
BLM indicates the decision supports Executive Order 13783, Promoting Energy Independence and Economic Growth; and Secretarial Order 3349, American Energy Independence. It does not authorize any actual drilling and any future proposals for leasing or development will be subject to additional environmental review based on site-specific project information and other requirements for consultation, coordination and public involvement.
The bureau estimates oil and gas activity on private and public lands directly supports approximately 3,000 jobs and $620 million in tax revenue within BLM’s Central Coast Field Office jurisdiction.
WASHINGTON–The Government Accountability Office is recommending the federal government increase its minimum bond rates for oil and gas wells on public lands, saying current levels are insufficient to pay for reclamation of orphaned wells.
A September GAO report, Bureau of Land Management Should Address Risks from Insufficient Bonds to Reclaim Wells, says BLM identified 89 new orphaned wells between July 2017 and April 2019 as well as $46 million in estimated reclamation costs associated with orphaned wells and with inactive wells that officials deemed to be at risk of becoming orphaned in 2018.
“In part, bonds have not prevented orphaned wells because bond values may not be high enough to cover the potential reclamation costs for all wells under a bond, as may be needed if they become orphaned,” GAO indicates.
According to the report, the average value of bonds held by BLM for oil and gas wells was slightly lower on a per-well basis in 2018 ($2,122) as compared with 2008 ($2,207). It notes the total value of bonds held by BLM for oil and gas operations increased between those years, as did the number of wells on federal land. It asserts that bonds that are held by the bureau have not provided sufficient financial assurance to prevent orphaned wells. Thus, BLM would have to pay for any remaining reclamation costs.
“GAO’s analysis indicates most bonds (84%) that are linked to wells in BLM data are likely too low to reclaim all the wells they cover,” the report says. “Bonds generally do not reflect reclamation costs because most bonds are set at their regulatory minimum values, and these minimums have not been adjusted since the 1950s and 1960s to account for inflation.”
According to GAO’s review of BLM data, although the total value of bonds held by BLM for oil and gas operations was higher in 2018 than in 2008 ($204 million compared with $188 million, in 2018 dollars), the average bond value per well was slightly lower because the number of wells on federal land also was higher in 2018 (96,199 compared with 2008’s 85,330). Specifically, it says, BLM held bonds worth an inflation-adjusted average of $2,207 a well in 2008. The bureau held bonds worth an average of $2,122 a well in 2018, a 3.9% decrease.
GAO also points out those bond minimums don’t account for variables such as number of wells they cover or other characteristics that affect reclamation costs, such as well depth. Without adjusting bond levels to closely reflect expected reclamation costs, the office warns that BLM faces ongoing risks that not all wells will meet the legal requirement of being completely and timely reclaimed.
“Regulatory bond minimums have not been adjusted since the 1950s and 1960s to account for inflation,” GAO says. “When adjusted to 2018 dollars, the $10,000 individual lease bond minimum would be about $66,000, the $25,000 statewide bond minimum would be about $198,000, and the $150,000 nationwide bond minimum would be about $1,187,000.”
WASHINGTON–President Donald Trump was touting the framework of an incremental trade agreement with China less than a week after his administration signed a formal trade deal with Japan.
“We have come to a deal, pretty much, subject to getting it written,” published reports quote Trump, regarding the China deal. Media sources also quote China’s Ministry of Commerce as saying “the two sides have made substantial progress” and have “agreed to work together in the direction of a final agreement.”
According to media accounts, the deal is an unwritten framework in which China will more than double its purchases of U.S. agricultural commodities, comply with some intellectual property measures and accommodate several U.S. positions regarding financial services and currency. The United States, meanwhile, has refrained from implementing a scheduled tariff increase on Chinese goods. The pledges, which Trump characterizes as “phase one” in a series of agreements, could be signed later this fall.
Other evidence of thawing U.S.-Chinese trade relations includes a liquefied natural gas deal between U.S. and Chinese entities. The agreement, in which Sempra LNG says it will supply LNG to China Three Gorges Corp., is the first of its kind since China imposed a 10% retaliatory tariff on U.S. LNG in September 2018, a rate that later climbed to 25% in June, press accounts note.
Meanwhile, in early October, the U.S. Trade Representative’s office reported the United States and Japan had reached agreement in the areas of market access for certain agriculture and industrial goods, as well as on digital trade. Under the deal, Japan will eliminate or lower tariffs for certain U.S. agricultural products. For other agricultural goods, Japan will provide preferential U.S.-specific quotas. Once implemented, USTR says, more than 90 percent of U.S. food and agricultural products imported into Japan will be either duty free or receive preferential tariff access.
“The United States looks forward to further negotiations with Japan for a comprehensive agreement that addresses remaining tariff and nontariff barriers and achieves fairer, more balanced trade,” the USTR says.
However, October also offered signs of more U.S. protectionism, when the U.S. Department of Commerce announced findings on several new dumping determinations, including an affirmative final determination in the antidumping duty investigation of imports of carbon and alloy steel threaded rod from Thailand, finding that that exporters had sold carbon and alloy steel threaded rod at less than fair value in the United States.
According to the department, since the beginning of the Trump administration, Commerce has initiated 184 new antidumping and countervailing duty investigations, a 235% increase from the comparable period in the previous administration.
WASHINGTON–October saw delays on three pipeline projects opposed by anti-development activists.
According to press accounts, the Mountain Valley Pipeline in mid-October saw the U.S. Court of Appeals for the 4th Circuit freeze two permits that MVP required to proceed with construction. Shortly thereafter, the Federal Energy Regulatory Commission ordered a halt to construction along the pipeline’s entire route.
The litigation originated in August, when groups including Wild Virginia and the Sierra Club filed a petition for review of the U.S. Fish & Wildlife Service’s biological opinion and incidental take statement, claiming that USFWS failed to protect endangered species, reports say.
Although October’s court action stayed the permits, the court also granted USFWS’s cross-motion to suspend the case until the agency could revise and reissue the documents. Press accounts cite a ClearView Energy Partners analysis that, while litigants can seek further judicial review of any revised approvals, they must initiate an entirely different case to do so.
According to the joint venture behind the MVP project, it would transport as much as 2 billion cubic feet a day of natural gas 303 miles from northwestern West Virginia to southern Virginia. Media reports indicate an MVP spokesperson has said the total project work is approximately 90 percent done.
Meanwhile, other published reports note, although TC Energy originally had planned to begin preconstruction on its 1,184-mile, 830,000 barrel a day Keystone XL oil pipeline project on Oct. 1, the company now says it will postpone work for the rest of 2019. The announcement came in mid-October, as Judge Brian Morris with the U.S. District Court for the District of Montana held a hearing on a petition from the Indigenous Environmental Network and North Coast Rivers Alliance to halt activities such as pipe transport, worker camp preparations, tree cutting and road maintenance. The groups are urging the court to nullify a second presidential permit President Donald Trump issued for the project, which would begin in Hardisty, Alberta, and extend south to Steele City, Ne. (AOGR, May 2019, pg. 28).
According to media reports, the PennEast pipeline also encountered a roadblock in October when the New Jersey Department of Environmental Protection denied necessary permits for the project. According to the joint venture behind PennEast, the 1 Bcf/d project will originate in Luzerne County, Pa., and terminate at Transco’s pipeline interconnection in Mercer County, N.J.
Published reports note that DEP’s rejection cites a September ruling by the U.S. Court of Appeals for the 3rd Circuit that prevents PennEast from condemning state-owned land in New Jersey that has been preserved for farmland and open space.
Despite the setbacks, reports indicate the companies behind all three pipelines remain committed to their projects.
CHEYENNE, WY.–Some energy producers won a split judicial decision when a federal court upheld a preliminary injunction against the Office of Natural Resources Revenue’s valuation rule as it applies to coal produced on federal and Indian lands. However, the U.S. District Court of Wyoming, ruling in Cloud Peak Energy v. U.S. Department of the Interior, said the decision would not include similar legal resolution sought by the oil and natural gas sector.
ONRR published the rule in 2016, changing how lessees calculate the value of natural resources when paying royalties on the oil, gas and coal produced on federal and Indian lands, the court decision describes.
The Trump administration attempted to repeal the rule early in 2017 and replace it with the former valuation methods. A federal judge vacated this repeal rule in March 2019, saying ONRR violated the Administrative Procedure Act. Three months later, ONRR ordered lessees to adhere to the 2016 rule in their calculations for paying royalties.
Cloud Peak, joined initially by the National Mining Association and Wyoming Mining Association, and later by the American Petroleum Institute, filed suit, alleging the 2016 valuation rule violated APA, was arbitrary and capricious, and exceeded ONRR’s authority, the court decision states. The Independent Petroleum Association of America filed an amicus curiae brief supporting the petitioners.
U.S. District Judge Scott Skavdahl’s decision supports the injunction request regarding the rule’s application to coal valuations, saying the petitioners established the legal requirements for an injunction.
He stated he saw no likelihood for success for challenges to the methodologies underlying oil and gas valuations. The decision says the rule is unlikely to be found arbitrary or capricious, citing ONRR’s examination of relevant data and articulating a satisfactory explanation for changing the methods used to value produced oil and gas. He points to the 21 pages included in the published valuation rule that summarized 1,000 pages of written comments and the agency’s explanations.
In response to the complaint that the rule ignored key legal and economic concerns, Skavdahl held that agencies were not required to adopt comments during proposed rule makings, but only must demonstrate responding to significant comments during the public comment period, which he says ONRR did.
The complaint also contends the rule erroneously requires arm’s-length contracts to be in writing and signed by all parties, or a default provision may allow ONRR to calculate the value of the fossil fuel, which the petitioners say is an outdated requirement inconsistent with current procedures. The decision asserts ONRR agreed oral contracts are legally binding but noted those contracts and their written follow-ups by letter or email significantly impede or render impossible its duty to audit lessee’s royalty payments.
WASHINGTON–The U.S. Environmental Protection Agency’s 2018 rule that allowed upwind states to contribute to high levels of ozone in downwind states must be changed, a federal court says.
Ruling in State of New York v. EPA, the U.S. Court of Appeals for the District of Columbia Circuit vacated the agency’s Close-Out Rule, which said upwind states exceeding National Ambient Air Quality Standards (NAAQS) for ozone didn’t have to take any additional actions in relief of downwind states’ ozone concentrations.
According to media sources, the Trump-era Close-Out Rule relied on the Cross-State Air Pollution Rule (CSAPR) introduced under President Barack Obama. In September, the appeals court ordered EPA to re-examine the 2016 regulation. The Wisconsin v. EPA decision ordered the agency to rework the rule to ensure upwind states reduce emissions of ozone precursors by the same deadline imposed on downwind states meeting federal ozone standards.
“EPA acknowledges (that) the Close-Out Rule ‘relied upon the same statutory interpretation of the Good Neighbor Provision’ that we rejected in Wisconsin. Thus, the agency’s defense of the Close-Out Rule in these cases is foreclosed,” the D.C. court wrote.
EPA issued the 2016 rule on behalf of 22 upwind states, the court says. It imposed emission reductions that the agency said would diminish, but not eliminate, the states’ significant contributions to downwind nonattainment by a 2018 deadline. In 2018, EPA released the Close-Out Rule Determination Regarding Good Neighbor Obligation for the 2008 ozone NAAQS. Court documents say it purported to resolve the Good Neighbor obligations of 20 upwind states for the 2008 standard.
“The EPA found that it would not be feasible to impose any cost-effective emissions reductions before 2023–two years after the serious areas attainment deadline in 2021,” the court states. “The EPA further found that all downwind states would reach attainment by 2023, even with no further reductions from upwind states. For those reasons, the Close-Out Rule required no further upwind reductions beyond those set forth in the CSAPR update.”
The D.C. court says EPA is considering whether to seek a rehearing or rehearing en banc in Wisconsin, as well as State of New York.
HARRISBURG, PA.–Pennsylvania Governor Tom Wolf in early October signed an executive order to bring his state into the Regional Greenhouse Gas Initiative (RGGI), a multistate greenhouse gas emissions cap-and-trade program, reports the Pennsylvania Independent Oil & Gas Association, which adds that the move has drawn objections from some legislators who question the governor’s authority to do so.
According to PIOGA, Wolf’s Oct. 3 EO requires the Pennsylvania Department of Environmental Protection to develop by July 31, 2020, a proposed rule-making package to abate, control or limit carbon dioxide emissions from fossil-fuel-fired electric power generators. It also requires DEP to work with the Public Utility Commission to engage with PJM Interconnection–which coordinates the movement of wholesale electricity in the region–to integrate the program.
A report by the Allegheny Institute for Public Policy notes that RGGI requires fossil-fueled electric power generators with a capacity of at least 25 megawatts to buy allowances equal to the CO2 emission caps the program has allotted. Participating states auction the allowances and are supposed to invest the revenue in energy efficiency, renewable energy and other consumer benefits.
The analysis points to studies showing 64% higher electricity rates in RGGI states, while noting that the Keystone State already has excelled at cutting GHGs. “Natural gas, which emits less CO2 than coal, has largely replaced coal as the leading fuel for generating electricity in the state,” it notes. “The Environmental Protection Agency’s data for CO2 emissions in Pennsylvania showcases the extraordinary results: CO2 emissions in the state from 2000 to 2016 fell 26%.”
PIOGA notes that the Wolf administration cites Pennsylvania’s 1960 Air Pollution Control Act and the federal Clean Air Act as the statutory authority for its move. Wolf has deemed the EO as a way for Pennsylvania to fight climate change, but media reports cite Mike Straub, a spokesman for Republicans in the Pennsylvania House of Representatives, differing with that rationale.
“We believe the executive branch cannot bind the state into multistate agreements without the approval of the general assembly, and we plan to execute the fullest extent of our legislative power on behalf of the people of Pennsylvania,” Straub is quoted.
The Allegheny Institute indicates the RGGI emissions allowance rules govern 165 facilities. The initiative was founded in January 2009, and participating states are Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, Vermont and New Jersey.
WASHINGTON–U.S. crude oil exports rose to an average of 2.9 million barrels a day during the first half of 2019, an increase of 966,000 bbl/d from the first half of 2018, and set a record-high monthly average of 3.2 MMbbl/d in June, the U.S. Energy Information Administration reports.
“Between January 2016 (the first full month of unrestricted crude oil exports) and July 2019, U.S. crude oil production increased by 2.6 MMbbl/d and export volumes increased by 2.2 MMbbl/d,” EIA observes.
Net imports (crude oil imports less exports) averaged 4.2 MMbbl/d in the first half of 2019, compared with 6.1 MMbbl/d during the same period a year ago, the agency adds.
EIA mentions that the number of U.S. crude oil destinations now exceeds the number of places exporting crude to the United States. In 2009, it says, the United States imported crude oil from as many as 37 sources in a given month, whereas in 2019, the maximum number of monthly import sources fell to 27. From January through June, the United States exported to as many as 31 destinations a month, the agency reports.
Canada remained the top destination for U.S. crude oil exports at more than 450,000 bbl/d, EIA says. However, it notes that export volumes to Canada did not change much between the first halves of 2018 and ’19, while exports to most other major destinations increased. China has been the exception to this trend, EIA says, falling 64%.
Exports to Thailand increased 266%, the agency reveals, while exports to South Korea went up 246% and exports to the Netherlands rose 192%.
EIA says the top regional destination for U.S. crude exports in the first half of the year was Asia and Oceania at 1.3 MMbbl/d, up 58% from the same period in 2018. Exports to Western European destinations averaged 824,000 bbl/d from January to June, up 66% from the first half of 2018.
EIA notes the increase in domestic oil production primarily has been relatively light-sweet crude, while most U.S. refineries are configured to process medium- to heavy-sour crude. “U.S. refineries have accommodated this increase in (light-oil) production by displacing imports of light and medium crude oils from countries other than Canada, and by increasing refinery utilization rates,” EIA says.
“More stringent national and international regulations limiting the sulfur content of transportation fuels also are affecting demand for light-sweet crude,” the agency continues. “Many of the less complex refineries outside the United States cannot process and remove sulfur from heavy-sour crude oil and are better suited to processing light-sweet crude into transportation fuels with lower sulfur content.”
WASHINGTON–Underground natural gas storage in the United States stood at 3.695 trillion cubic feet on Oct. 25, 1.4% above the five year average, according to the U.S. Energy Information Administration. That was 558 Bcf more than a year ago, when gas storage stood at 3.137 Tcf.
According to EIA, gas storage in the East Region was 913 Bcf on Oct. 25, 2.0% above the five-year average and 87 Bcf more than it was a year ago.
Gas storage in the Midwest Region stood at 1.095 Tcf on Oct. 25, 3.6% above the five-year average and 142 Bcf more than a year ago.
In the Mountain Region, EIA says, gas storage was 211 Bcf on Oct. 25, right on the five-year average, but 31 Bcf more than a year ago.
Gas storage in the Pacific Region was 298 Bcf on Oct. 25, 8.0% below the five-year average and up 36 Bcf from a year ago.
In the South-Central Region, gas storage levels on Oct. 25 were 1.178 Tcf, 1.9% above the five-year average and up 262 Bcf from a year ago.