U.S. power plants likely used more gas than coal in 2015
(Reuters; Jan. 20) - Last year looks like it was an unwelcome watershed for the embattled U.S. coal industry. Power companies in 2015 for the first time may have burned more gas than coal to generate electricity, according to analysts who attribute it to the cheapest gas prices in 16 years and a record number of coal-fired plants retired from service because of the high cost of meeting environmental regulations. The U.S. power sector burned a record 26.4 billion cubic feet of gas per day on average last year.
Data from the U.S. Energy Information Administration showed that power plants used more gas than coal to produce electricity in five of the first 10 months of 2015, including the last four months that data was available (July, August, September and October.) While EIA does not forecast that gas produced more electricity than coal in 2015, some analysts conclude it did because gas in November and December traded at the lowest levels for the entire year, prompting more coal-to-gas switching.
Coal has been the primary source of fuel for U.S. power plants for the past century, but its use has been declining since peaking in 2007, which is expected to continue as the federal government imposes rules to limit carbon emissions. Thomson Reuters Analytics estimated coal-to-gas switching in November and December averaged 8.7 billion cubic feet of gas per day. Ten years ago, coal produced 50 percent of the nation's power supply, while gas was at just 19 percent. Now, both fuels are at about 33 percent.
U.S. Forest Service opposes gas pipeline route to eastern shore
(The Daily Progress; Charlottesville, VA; Jan. 21) - The U.S. Forest Service has rejected the latest proposed route of the Atlantic Coast Pipeline because of the 42-inch natural gas pipeline’s potential damage to the habitat of sensitive animal species protected by two national forests in Virginia and West Virginia. The Forest Service submitted its comments to the Federal Energy Regulatory Commission, which is reviewing the application for the 550-mile pipeline.
The Forest Service said the proposed route is “inconsistent” with its plans and commitments to protect the habitats of the Cow Knob salamander, Cheat Mountain salamander and West Virginia northern flying squirrel, as well as the red spruce forest ecosystem in which they live. The pipeline, estimated to cost $5 billion, would move Marcellus Shale gas through West Virginia to North Carolina and Virginia.
The pipeline project does not meet the agency’s minimum requirements for a special-use permit to cross the George Washington and Monongahela national forests, said Kathleen Atkinson, regional forester for the Eastern Region, and Tony Tocke, regional forester for the Southern Region. “Therefore, alternatives must be developed to facilitate further processing of the application,” the agency said.
Cheniere seeks to refinance debt on underused LNG import terminal
(Bloomberg; Jan. 22) - Cheniere Energy is seeking to borrow about $2.6 billion to refinance its underused Sabine Pass liquefied natural gas import facility and a pipeline, according to four people familiar with the deal. Cheniere, which is better known because it’s on track to export the first LNG cargo of U.S. shale gas this year, owes about $2.1 billion on the import facility in Louisiana, with $1.67 billion due in November, according to a company presentation Jan. 21.
Thanks to the U.S. shale boom, the $1.6 billion Sabine Pass import terminal was redundant the moment it came online in 2009. U.S. gas production is expected to climb in 2016 for the 11th straight year, and gas futures that soared to more than $13 per million Btu in mid-2008 plunged in December to a 16-year low of $1.68. The import plant has never operated at full capacity, and soon after it began operations the company started planning an adjacent export facility.
The financing would replace all existing debt on the Creole Trail Pipeline and the LNG import terminal, and add some new debt. Cheniere receives minimal quantities of imported LNG, mainly maintenance shipments to keep the plant running, according to government data compiled by Bloomberg. Total and Chevron each contracted for 1 billion cubic feet of import capacity at the plant and began making annual payments totaling $250 million when the terminal came online under 20-year agreements.
India could start U.S. LNG imports in 2017
(Live Mint; India; Jan. 20) - India is to receive its first imports of U.S. shale gas in 2017, a person familiar with the development said Jan. 19, a move that is expected to help India in its quest to broaden its energy supply mix. Liquefied natural gas imports from the U.S. are expected to be a cost-effective fuel source for India’s fertilizer manufacturers and power producers that are unable to operate at full capacity for lack of enough of the cleaner-burning fuel from domestic sources.
GAIL (India) has contracts to bring in 6 million metric tons a year (almost 300 billion cubic feet of gas) of U.S. LNG, the source said. GAIL has contracts with Cheniere Energy’s export terminal under construction at Sabine Pass, La., and the Cove Point project being built on the Maryland shore. India consumed almost 1.8 trillion cubic feet of gas in 2014, about 60 percent produced domestically and the rest imported. Most of its LNG imports come from Qatar, with smaller volumes from several other suppliers.
Novatek CEO says Yamal LNG still talking with China for financing
(Wall Street Journal; Jan. 22) - The chief executive of Novatek, Russia’s second-largest gas producer, indicated Jan. 22 that the company was closing in on loans from Chinese and Russian banks for its Arctic liquefied natural gas project, but gave no timeline for concluding any credit agreements. Novatek CEO Leonid Mikhelson said the Yamal LNG project had secured loan guarantees of $4 billion from the Export Insurance Agency of Russia and was in talks over $12 billion in credits from Chinese banks.
Novatek has missed several self-imposed deadlines — most recently the end of last year — for securing funding for Yamal LNG, forcing the company and its partners, France’s Total and China National Petroleum Corp., to invest billions of their own funds and turn to the Kremlin for a bailout. The project is a test for Russia’s ability to weather Western sanctions. U.S. restrictions on Novatek have squeezed financing for the project, which is at the center of Russia’s attempts to increase LNG exports to Asia.
Mikhelson said $12 billion in funding would come from Chinese banks, mostly in euros, but that discussions on the currency for the loans were not finished. Talking to reporters at the World Economic Forum in Davos, Switzerland, Mikhelson said Russian lenders Sberbank and Gazprombank would provide loans of $4 billion in total under guarantees from the Export Insurance Agency of Russia. Yamal LNG, which is under construction, is supposed to start deliveries from its first production unit, mostly to Asia, in late 2017.
Mitsubishi takes over U.S.-based oil and gas marketer
(Bloomberg; Jan. 20) - Japan’s Mitsubishi has bolstered access to gas supplies for its North American export projects by taking full ownership of oil and gas marketer Cima Energy. Mitsubishi, which already held 34 percent of Cima, took control of the Houston-based company, it said Jan. 20. It did not provide a value for the transaction. Mitsubishi will use Cima to obtain supplies for liquefied natural gas export projects it holds stakes in, including Cameron LNG in Louisiana and LNG Canada in British Columbia.
Cima trades about 1 billion cubic feet of gas a day, according to Mitsubishi. Mitsubishi originally bought a piece of Cima in 2008 to market natural gas supplied from LNG imports to the United States. The subsequent U.S. shale boom upended those plans, turning many of the prospective U.S. LNG import terminals into export projects.
Mitsubishi’s move comes as LNG prices are pacing a collapse in oil amid a global supply glut and tepid demand from utilities amid cheaper alternative fuels. New LNG projects coming online in the U.S and Australia, the gradual restart of nuclear reactors in Japan and low coal prices are driving LNG prices lower, analysts at Citigroup said in a report Jan. 19. The spot price for LNG shipped to northeast Asia has tumbled to $6.45 per million Btu, matching the lowest in data going back to 2010.
‘Unfortunate timing’ for Chevron’s Gorgon LNG in weak market
(Bloomberg; Jan. 20) - After years of delays, cost overruns and labor unrest, Chevron’s Gorgon project, one of the world’s most expensive liquefied natural gas ventures, faces another challenge: the weakest energy prices in over a decade. As Chevron prepares for its first export from the facility in northwest Australia, oil prices — which traditionally determine the value of LNG — are near 12-year lows. The project will add to a wave of new supply, including the first deliveries from the U.S., amid weakening demand.
Gorgon highlights the risk of investing in major energy projects amid unpredictable and volatile prices. Crude has more than halved since Chevron decided to go ahead with the project in 2009, and its cost has ballooned to $54 billion from $37 billion. The company said it is focused on returns over four decades, but current market conditions will reduce near-term cash flows. “It is unfortunate timing to start up a long-gestating LNG project in such a weak market,” said James Taverner, a Tokyo-based analyst at consultancy IHS.
“Falling oil and LNG prices will greatly affect the economics of all new projects coming online now,” Taverner said. “Gorgon is one of the most expensive LNG projects in the world. Low LNG prices will hurt its margins.” Spot LNG prices in northeast Asia have tumbled by more than two-thirds since early 2014, sliding to $5.65 per million Btu, the lowest since at least 2010. “The real bloodbath for spot LNG” prices will come later, said Jeff Brown, president of consulting firm FGE in Singapore, who estimates prices may fall further and trade in the $4 to $5 range between the second half of 2016 and 2018.
Small LNG export project wins Canadian export license
(CFTK-TV; Terrace, BC; Jan. 20) - One of the Northwest's smaller LNG projects now has an export license from the National Energy Board. The board last week granted a 25-year export license to AltaGas for its Douglas Channel LNG project near Kitimat, B.C. AltaGas and its Japanese and European partners are planning a floating liquefaction and export facility that is tiny — 550,000 metric tons of LNG a year — compared to other multimillion-ton proposals for the coast at Kitimat and Prince Rupert.
Calgary-based AltaGas is leading the venture, which estimates project costs at $500 million. A final investment decision could come this year, although the venture is fighting with the Canadian government over whether it should have to pay hefty import duties on its floating processing plant that would be built overseas. The project would be on Haisla First Nation territory.
Global LNG project review ranks Australia as high cost
(LNG World Shipping; Jan. 22) - LNG World Shipping has assessed the cost per tonne of output capacity for 37 liquefied natural gas production and export projects in play 2013 to 2021. The results highlight some obvious conclusions — Australia has been a high-cost place to bring seven challenging, world-scale projects online simultaneously. The review looked at projects completed since 2013, those under construction, those that could start up by 2021, and several that have been canceled the past three years.
The review excluded the costs associated with financing, and concluded that direct cost comparisons are fraught with difficulties because each project is unique, comprising a range of variables. Aside from the terminal’s location, other variables included logistics and market conditions, choice of technologies, local and geopolitical issues, investment decision timing and human factors. All invariably have a role to play in any cost profile.
The widest contrast is between the U.S. and Australia. Projects in both will see longer payback times then they had planned when making investment decisions years ago, during better prices and stronger markets. The Australian projects cost an average $3,000 per tonne capacity vs. the U.S. average of under $1,000. The Australia projects were high-cost greenfield ventures in a costly construction environment that included gas field development costs and pipelines. The U.S. projects mostly were brownfield projects that rely on unused LNG import terminals for much of the needed infrastructure.
BP looks to double natural gas production in Egypt
(Reuters; Jan. 19) - BP aims to double its gas production in Egypt in the next four years despite weak oil prices as Egypt's burgeoning energy market needs more fuel. Egypt is on a drive to ramp up oil and gas production — aggressively signing exploration deals, renegotiating production prices and lobbying companies to speed up projects even as firms worldwide scale back. Through joint ventures with Italy's Eni and the Egyptian government, BP produces 10 percent of Egypt's oil and 30 percent of its gas.
The company says it has no intention of backtracking on its pledge to speed up production at recent discoveries. "BP's plan is to double our gas production in Egypt before the end of this decade," BP North Africa regional president Hesham Mekawi said. BP currently produces around 1.4 billion to 1.5 billion cubic feet of gas per day in Egypt. BP's plans come as oil prices hit 12-year lows and the company last week announced it would slash 5 percent of its global workforce, as many as 20,000 jobs.
Major finds such as Zohr, a Mediterranean gas field discovered by Eni in August, have kept companies interested in Egypt, where massive deposits remain untapped. The lion's share of additional gas production that BP will bring online in the next few years will come from its West Nile Delta project, which is expected to reach 1.2 billion cubic feet per day starting in 2017, Mekawi said. The country’s energy shortage has forced it to pay dearly to keep homes lit and factories running. Egypt will spend an estimated $8 billion on energy imports this fiscal year, the oil minister said recently.
BP diverts LNG cargo away from Egypt over unpaid bills
(Reuters; Jan. 21) - BP's diversion of a tanker of liquefied natural gas away from Egypt due to payment issues is the first sign that the country's currency crisis could be jeopardizing its energy supplies, traders said. Earlier this month the tanker British Sapphire was diverted to Brazil rather than discharging in Egypt, with the delivery of the LNG cargo for Egypt delayed up until October, traders said. BP declined to comment. Egypt's state-owned EGAS was not available to comment.
Egypt has been struggling to pay for U.S. dollar-priced oil products and LNG due to an acute foreign currency crisis, worsened by the Russian airliner disaster in October that hit tourism revenue. Egypt, which is short domestic gas production, became a major market for LNG shippers last year after start-up of two import terminals, but a payment freeze until March has left more than $400 million in unpaid bills so far, sources said.
It is an unwelcome addition to Egypt's already growing arrears to foreign oil companies involved in producing oil and gas in the country. In BP's case this has begun to translate into LNG deliveries being pushed back nine months into the future in the latest case, a source said. BP's British Sapphire arrived outside Egypt’s Ain Sokhna import terminal Dec. 24 and proceeded to spend the next two weeks circling offshore. Its destination changed Jan. 7 and it is currently en route to Brazil, shipping data shows. "The British Sapphire was redirected because [BP's] previous cargo was not paid for," a trader said.
Oklahoma driller agrees to shut in wastewater disposal wells
(Wall Street Journal; Jan. 20) - After days of negotiations with Oklahoma regulators, an embattled oil producer has agreed to shut down several wastewater disposal wells that had been linked to earthquakes in the state. The agreement comes after Sandridge Energy refused a request from regulators in December to close the wells, which are part of its oil-and-gas fracking operations. But facing legal action, the company brokered a deal with the state.
By early February, Sandridge will stop using seven wells located near a spate of earthquakes that recently rocked a region 100 miles northwest of Oklahoma City. Three will be closed entirely, according to the Oklahoma Corporation Commission, which oversees the state’s oil and gas industry. The other four, plus a previously unused well, will be given over for earthquake research. Sandridge also agreed to reduce the amount of wastewater injected into roughly 40 other wells it will continue to use in the area.
The company — which was recently delisted from the New York Stock Exchange — had warned in financial filings that curtailing its use of disposal wells could force it to dial back on production, which would hurt revenues. Regulators said the agreement with Sandridge provides an opportunity for the Oklahoma Geological Survey to use the five wells given over by the company to study the rising number of earthquakes in the state. A growing body of research links quakes to the use of drilling wastewater disposal wells.
Montreal regional council opposes TransCanada oil pipeline
(Montreal Gazette; Jan. 21) - The Montreal Metropolitan Community, representing 82 municipalities in the Montreal region, announced Jan. 21 it opposes the proposed Energy East pipeline that would move Alberta oil sands production more than 2,800 miles to Canada’s eastern shore. Montreal Mayor Denis Coderre, who also serves as president of the metropolitan community, said the group decided, after a series of public meetings, that the environmental risks outweigh the economic benefits of the pipeline.
Marc Demers, mayor of Laval, Quebec’s third-largest city with about 400,000 residents, said last fall that the city “unequivocally opposes the pipeline because of environmental concerns, citizen safety and the threat of spills in the island-city’s waterways.” If built, the $15.7 billion pipeline project promoted by TransCanada could transport 1.1 million barrels of oil a day to refineries and to tidewater for export. More than 60 miles of pipe would cross land belonging to 10 cities of the Montreal Metropolitan Community.
TransCanada has said it understands community concerns, but argues pipelines are the safest means of transporting oil. It cites a 2013 report by the Fraser Institute that found pipelines are 4.5 times safer than using trains. Blocking a pipeline, TransCanada argues, will result in more oil moved in Canada by train. Business groups have pushed for the pipeline, saying it would create thousands of jobs. Opposition parties argue the risks of having a pipeline run through Quebec’s lakes and rivers outweigh its benefits.
Canadian oil pipeline proposals all face hurdles
(The Canadian Press; Jan. 21) – Canadian oil pipeline proposals just can't catch a break these days. The latest hurdle came this week when an organization representing 82 Montreal-area municipalities came out against TransCanada's Energy East Pipeline, drawing a sharp rebuke from politicians in Alberta and Saskatchewan who support the line from Alberta to the Atlantic Ocean. Here is an update on other pipeline projects:
Keystone XL: TransCanada says it is not giving up on pipeline to move oil sands production to the U.S. Gulf Coast, despite rejection by President Barack Obama after almost seven years of waiting. The company is taking the U.S. government to court
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Northern Gateway: Enbridge's pipeline would ship 525,000 barrels a day of oil sands crude to Kitimat, B.C., for export to overseas buyers. Northern Gateway has been hugely controversial. Enbridge has had a federal permit since mid-2014, but a recent B.C. Supreme Court ruling on First Nation issues and a change of government in Ottawa have caused critics to declare Northern Gateway "dead in the water."
Trans Mountain: The Canadian arm of U.S. energy giant Kinder Morgan is aiming to nearly triple the capacity of its existing Trans Mountain pipeline to 890,000 barrels of oil a day to provide an outlet for oil sands production to reach the B.C. coast. The project is in the thick of the National Energy Board review, and has faced stiff opposition from those who do not want to see more crude-filled tankers moving through coastal waters.