Exxon, Saudi partner pick Texas site for $9 billion ethane plant
(San Antonio Express; April 19) - ExxonMobil is moving forward with plans to build the world’s largest ethane steam cracker plant on a 1,400-acre plot of bucolic farmland just north of Corpus Christi, Texas, following a six-month battle that left the 20,000 residents of the neighboring city of Portland divided. The decision comes after community protesters called Portland Citizens United unsuccessfully tried to block local tax incentives for Exxon and its foreign partner, Saudi Arabia Basic Industries Corp.
The group opposes the $9.3 billion facility because its proposed site is 1.75 miles away from a high school and junior high. The plant would use heat and pressure to turn gas into ethylene and polyethylene, the base materials used to make plastic. Exxon and its partner announced the site decision April 19, saying they will buy the land from a cotton-growing family if the state approves the companies’ permits.
The announcement “doesn’t change anything,” said Jason Mutschler, a member of Portland Citizens United. “We’re still going to fight this in the permitting stages.” Exxon Project Executive Rob Tully said air quality and wastewater permits were being filed this week with the state. Errol Summerlin, a member of Portland Citizens United, called the fight against the permits an “uphill battle.”
The state’s Texas Enterprise Fund has awarded $6.4 million for the project, which also was awarded more than $1.4 billion in tax incentives by the county and school district. The school board’s tax package requires Exxon to create at least 400 permanent jobs and over 15,000 temporary construction jobs. Exxon and its partner said they choose the site over Louisiana because of its proximity to shale gas fields in South Texas.
Chevron loses major tax case in Australia
(Australian Broadcasting Corp.; April 21) – Chevron faces one of the largest tax bills in Australian history after failing to overturn a federal court judgment pursued by the Australian Tax Office. The landmark ruling leaves Chevron facing a tax bill well over $300 million, as well as paying substantial costs, including those of the tax office. A federal court unanimously dismissed the appeal against the tax ruling that Chevron had used an intra-company loan to shift offshore and avoid tax on its Australian income.
The ruling examined a high-interest, $US2.5 billion loan from a Chevron subsidiary in Delaware to Chevron Australia. The decision may also have implications for a much larger $42 billion Chevron loan currently in place, which has a similar structure to the loan challenged in the court case. Chevron has invested tens of billions of dollars this decade in two LNG projects in Australia.
The case related to "internal refinancing" of Chevron Australia's debt to fund the acquisition of Texaco Australia after a merger between Chevron and Texaco. The loan, from a shell company, charged 9 percent interest to its Australian parent company. But U.S. Chevron raised money for the loan at an interest rate of just 1.2 percent. The loan had the dual impact of significantly reducing tax paid by Chevron in Australia, which could deduct the interest, while allowing U.S. Chevron to make big profits on the spread between the low borrowing rate of 1.2 percent and the high lending rate of 9 percent.
The court said the loan was not a genuine "arm's length" transaction. Campaigners against multinational tax avoidance welcomed the court decision. Chevron admitted in a 2015 Australian Senate hearing on tax avoidance that the current loan, which is under audit by the country’s tax office, could reduce tax payments in Australia by $15 billion.
Cheniere loads up 15 LNG cargoes at Sabine Pass in February
(Argus Media; April 19) - Louisiana's Sabine Pass LNG terminal in February exported 15 cargoes with a combined volume equivalent to 52 billion cubic feet of gas, according to data recently released by the U.S. Department of Energy. It was a new record as production at the Cheniere Energy facility continues to ramp up. January’s total was 51 bcf. The Sabine Pass LNG terminal is the first in the Lower 48 states, with more scheduled to come on line later this year and in 2018.
Of February’s cargoes, five went to Asia, five to Latin America, three to Europe and two to the Middle East. Of those 15 tanker loads, 11 were exported by Shell, Spain's Gas Natural Fenosa or Cheniere under long-term contracts, according to an Argus Media analysis of the data. The four remaining cargoes, including three test cargoes from the plant’s third liquefaction train, were sold on a spot basis at a volume-weighted average price of $5.88 per million Btu. The buyers were responsible for shipping charges.
Shell paid $6.15 per million Btu for its four February cargoes under a 20-year contract with Cheniere. That includes the cost of feed gas plus 15 percent more for gas used during liquefaction, plus a liquefaction fee to Cheniere. Shell is contracted to pay Cheniere $2.25 per million Btu of reserved plant capacity, regardless if it uses the plant and takes any LNG or not. (Shell also has another contract with a $3 fee.) Gas Natural paid $6.49 in February, with a capacity reservation fee of $2.49 per million Btu.
Environmentalists vow to target natural gas next, after coal
(Bloomberg; April 20) - Think coal has it bad in the fight against climate change? Watch what happens to natural gas. Power plants around the world are stepping up their use of gas because it burns cleaner than coal — and in the U.S., at least, it’s cheaper. Gas now supplies about a third of the country’s power, up from just 17 percent a decade ago. But U.S. environmentalists have vowed to go after gas-fired power plants with the same vengeance they’ve used to force the retirement of hundreds of coal facilities.
Even coal miners are warning their fossil fuel kin to beware. Gas producers “will be next on the list of the industries to be destroyed,” said Robert Murray, CEO of U.S. coal miner Murray Energy. Coal lost its place as America’s No. 1 power plant fuel last year, dethroned by gas. More than 1,000 coal mines have closed since 2009, putting 36,000 people out of work. Researchers and energy executives alike warn that if gas can’t cut global-warming emissions, it’s only a matter of time before it shares the same fate.
Gas is often promoted as clean because it releases half as much carbon dioxide as coal. But methane, the most prevalent chemical compound in natural gas, is a potent greenhouse gas in its own right, with heat-trapping emissions at every stage of its life, from well to pipeline to power plant. The U.S. gas industry as a whole was responsible for more emissions than coal last year for the first time, according to Bloomberg New Energy Finance. To keep its product from falling out of favor, the gas industry has spent at least $10 billion developing technologies to capture carbon emissions.
Conoco considers transcontinental gas line to serve Australia
(Reuters; April 20) - ConocoPhillips will consider diverting natural gas from fields in northern Australia along a proposed transcontinental pipeline that would link directly to domestic markets in the southeast, a senior executive told Reuters on April 20. The company is also leaning toward developing the Barossa gas field offshore northern Australia, with a final decision due in the first quarter of 2018, said Kayleen Ewin, the company's vice president for sustainability, communications and external affairs.
Ewin said the transcontinental pipe would open Australia's domestic market for northern producers. The system would carry gas from the Northern Territory to Moomba in South Australia, the hub to the country's main southeastern markets. Australia's government said last month it would study and possibly contribute to building the pipeline. That offers an opportunity for developing gas in a region where Shell, Malaysia's Petronas, Italy's ENI, and Australia's Santos and Origin Energy have undeveloped interests.
A looming gas shortage for Australia's populous east has seen prices spike and the government search for solutions as more gas is drawn from the domestic market to meet liquefied natural gas export contracts. ConocoPhillips also announced it is considering adding a second production unit at its 11-year-old Darwin LNG plant in northern Australia and possibly processing gas from rivals' undeveloped fields. The plant’s current gas source, the Bayu-Undan field, is expected to run out about 2022.
Regulator approves small-scale LNG plant in northern B.C.
(Alaska Highway News; Fort St. John, BC; April 20) - Plans for an $18 million liquefied natural gas plant near Fort Nelson in northeastern British Columbia have received regulatory approval. The BC Oil and Gas Commission has granted KT Energy a permit to build and operate its proposed LNG plant, with construction expected to start next year. The facility, in development since 2015, would be located in the Maxhamish area 80 miles northwest of Fort Nelson, just south of the Yukon Territory border. The plant will have an initial capacity of 20,000 gallons of LNG per day, according to the company.
Because the existing gas pipeline network ends in Fort Nelson, the company views Fort Nelson as a gateway for a long-haul LNG supply for northern B.C., the Northwest Territories, the Yukon and even Alaska. It said it would use the Alaska Highway and Canada’s Highway 77 as a “virtual pipeline” to transport gas to off-grid communities and industrial and commercial users looking to replace fuels such as diesel with a more economic and environmentally friendly option.
The company hopes to start site preparation and construction next summer, with the plant scheduled to come online in late 2018. Any subsequent expansions would be tailored to market conditions. The company still needs to secure sales contracts for the LNG. KT Energy, based in Vancouver, is a member of Kai Tian Energy Group, a group of companies in China and Canada that has been in the natural gas sector since 2002, according to the company's website.
New owner of Conoco’s Canadian gas assets plans to boost spending
(Canadian Press; April 21) - Cenovus Energy plans to ramp up the drilling of conventional gas wells on the lands it is buying from ConocoPhillips in a $17.7 billion deal announced last month. The Calgary-based company intends to spend $650 million in 2019 to drill about 120 wells in what is known as the Deep Basin of northeastern B.C. and northwestern Alberta, CEO Brian Ferguson said April 21. That’s about five times the $120 million ConocoPhillips had planned to spend this year to drill 24 wells, he said.
The drilling will bring on new production to better utilize ConocoPhillips’ gas processing plants and pipelines, Ferguson said, thus improving the economic return from the play. “The infrastructure is 40 percent utilized — that’s one of the big opportunities for us,” he said. “Conoco has been starving the Deep Basin of capital; they had been allocating it elsewhere in the corporation.”
He said spending on the assets is expected to climb this year to $170 million and next year to $350 million, then $650 million in 2019. Cenovus said production from the Deep Basin properties could grow by more than 40 percent, from 120,000 barrels of oil equivalent per day in 2017 to about 170,000 in 2019. ConocoPhillips has said it wanted to sell the Canadian assets to pay down debt and to allocate capital to other energy investments with better rates of return than oil sands and natural gas.
Analysts question if Conoco can deliver growth after asset sales
(Reuters; April 20) - ConocoPhillips has beaten its 2017 asset sales target less than four months into the year, after shedding $30.8 billion worth of energy assets in six years. But instead of a chorus of cheers on Wall Street, CEO Ryan Lance is facing investor skepticism that the company can deliver growth from remaining oil and gas fields. ConocoPhillips' most recent sales of Canadian oil sands properties and U.S. gas wells for a combined $16 billion will part with nearly 30 percent of its proved reserves in order to deliver near-term shareholder payouts and reduce debt.
Lance said the sales to Cenovus Energy (oil sands) and Hilcorp Energy (Southwest U.S. gas assets) will fulfill promises to reduce long-term debt by 42 percent to $15 billion, fund $6 billion in share purchases and help reshape the company for an era of low and volatile energy prices. "I don't worry about production and reserves in the company," he said, citing fields that could be upgraded to proved reserves over time.
But portfolio managers and industry analysts point to the sales as a short-term fix. The company projects its daily production will fall 26 percent after the latest sales to about 1.16 million barrels of oil equivalent. Barclays expects it won't return to production growth on a full-year basis until 2019. ConocoPhillips is ramping up output from its Eagle Ford and Bakken shale wells, from another oil sands property and from liquefied natural gas from operations in Australia. To ensure growth, producers must continually add reserves to offset production and the natural decline of their oil-and-gas properties.
Canadian companies may do better at finding oil sands efficiencies
(Bloomberg; April 20) - Now that multinational energy producers have sold their stakes in Canada’s oil sands, local companies are hatching plans to make some real changes. Cenovus Energy and Canadian Natural Resources are betting they can exploit new technologies and benefit from their deeper understanding of Canadian-specific issues, such as environmental rules and relations with Native communities.
“The oil sands require a focus on environmental issues like carbon pricing, indigenous issues … that are very specific kinds of skills that companies need to have for Alberta, for Canada,” said Harrie Vredenburg, a professor at the University of Calgary’s Haskayne School of Business. “Some of the multinationals are not necessarily particularly suited to that. In all those things, it does favor the Canadian firms.” So far this year, non-Canadian companies have shed more than $20 billion in oil sands assets.
The oil sands produced about 2.4 million barrels per day in 2015, accounting for almost two-thirds of Canada’s output. With low prices, producers are searching for efficiencies. Companies including Canadian Natural Resources, Cenovus and Suncor Energy have agreed to share proprietary technologies royalty-free, a unique setup that may not have been possible without Canadian friendliness, said Dan Wicklum, CEO of Canada’s Oil Sands Innovation Alliance. “Canadians will always try to negotiate and to find common ground and collaborate before we become confrontational and adversarial,” he said.
Nebraska state utility board last permitting test for Keystone
(GreenWire; April 20) - Farmers and landowners in Nebraska are preparing a last stand against the Keystone XL oil sands pipeline, as the TransCanada project faces a final permitting test. Members of the group of ranchers and farmers say the pipeline is a threat to prime farming and grazing lands. They hope the economic argument will resonate better in the conservative state than environmental concerns have.
"It's depressing to start again after Obama rejected the pipeline two years ago, but we need to keep our coalition energized and strong," said Art Tanderup, a farmer who grows rye, corn and soybeans. The final permit for the Alberta-to-Central U.S. line will be decided by the Nebraska Public Service Commission, a five-member board with authority over the route. The commission has scheduled a public hearing in May and will hear a week of testimony in August before issuing a decision in November.
The five members of the commission are facing significant political pressure from outside parties. "The commissioners know it is game time, and everybody is looking," said Jane Kleeb, chairwoman of Nebraska's Democratic Party and a lead organizer against the pipeline. One member of the commission, Democrat Crystal Rhoades, is a member of the Sierra Club. Another, Republican Rod Johnson, has a history of campaign donations from gas and oil companies.
Minnesota reviews Enbridge proposal for new oil sands pipeline
(Duluth News Tribune; MN; April 16) – Calgary-based Enbridge calls it "the largest project in our history." Minnesota state officials say it "presents significant issues." Opponents say it could "desecrate our lands, violate our treaty rights or poison our water." Another oil pipeline fight is heating up. Enbridge is seeking the state of Minnesota's approval to build a new oil pipeline to replace its aging Line 3, which would expand capacity and carve a new path for pipelines across the state.
The Line 3 replacement is a new 36-inch-diameter pipeline to move 760,000 barrels of oil from Alberta to the Enbridge terminal in Superior, Minn. The 1,031-mile line will cost about $7.5 billion to build. About 337 miles of pipe will cross through Minnesota. "Line 3 is a replacement project intended to upgrade and improve the pipeline while restoring capacity to its original volume to meet the demands of refineries in Minnesota and the Midwest," company spokeswoman Shannon Gustafson wrote in an email.
The original Line 3 was built between 1962 and 1967, and runs at half its original capacity and requires increasing attention. Ultimately, that makes it more cost-effective to build an entirely new pipeline, the company said. "Line 3 has experienced external corrosion inherent and common in the pipe coatings used at the time the pipeline was constructed," Gustafson said. It will be up to the state to decide if a new line is in the public interest. Enbridge applied to the state in 2014.
Energy analyst predicts oil industry downturn is only starting
(The Financial Post; Canada; April 19) – “I usually put a £5 bet on the oil price — and I’m collecting,” smiles Professor Dieter Helm. It’s not difficult to imagine his tally adding up. The highly regarded Oxford University economics professor is a long-time industry observer. Still, his bets are trillions of dollars lower than the energy leaders he advises. If Helm is to be believed, the oil market downturn is only starting. The latest collapse is the harbinger of a global energy revolution that could spell the end-game for fossil fuels.
These theories were laughable less than a decade ago when oil prices grazed highs of more than $140 a barrel. But the burnout of the oil industry is approaching quicker than was first thought, and senior leaders within the industry are beginning to take note. In the past, the International Energy Agency has faced down criticism that its market forecasts have overestimated the role of oil and underplayed the boom in renewable energy sources. But last month the tone changed.
The agency warned oil and gas companies that failing to adapt to the climate-policy shift away from fossil fuels and toward cleaner energy would leave $1 trillion in oil assets and $300 billion in natural gas assets stranded. For companies that heed Helm’s advice, the route ahead is a ruthless harvest-and-exit strategy. This would mean aggressive cuts in capital spending, pumping of remaining oil reserves while keeping costs to the floor and paying out very high dividends. But Helm is not entirely convinced that oil companies have grasped the speed with which the industry is undergoing irrevocable change.