BP to increase share in UK’s giant Clair field and sell interest in Alaska’s Kuparuk field
Increasing holding in core oilfield, west of Shetland in UK, and selling non-operating interest in Alaskan asset.
Buying 16.5% in Clair field from ConocoPhillips; selling interest in Greater Kuparuk Area to ConocoPhillips.
Two transactions together expected to be cash neutral for BP.
This week, BP announced that it has entered into agreements with ConocoPhillips that will significantly increase its holding in the Clair field, a core asset of BP’s North Sea business in the UK, while also selling its non-operating interest in the Kuparuk and satellite oilfields in Alaska.
BP has entered into an agreement to purchase from ConocoPhillips a 16.5% interest in the BP-operated Clair field, west of Shetland in the UK, buying a ConocoPhillips subsidiary that will hold this interest in the field. As a result, BP will hold a 45.1% interest in Clair and ConocoPhillips will retain a 7.5% interest.
Separately BP has entered into agreements to sell to ConocoPhillips BP’s entire 39.2% interest in the Greater Kuparuk Area on the North Slope of Alaska as well as BP’s holding in the Kuparuk Transportation Company.
Details of the transactions are not being disclosed but, excluding customary adjustments, the transactions together are expected to be cash neutral for BP and ConocoPhillips. The transactions, which will be subject to State of Alaska, US federal and UK regulatory approvals and other approvals, are anticipated to complete in 2018.
“This is a further step in focusing our portfolio around core assets and developments which have the potential for significant growth. Clair is a key advantaged oilfield for our North Sea business, a giant resource whose second phase is about to begin production and which holds great potential for future developments,” said BP Upstream chief executive Bernard Looney.
“In Alaska, this transaction will increase our focus on managing our deep resource base at the massive Prudhoe Bay oilfield and help enable a more competitive and sustainable business for BP.”
The giant Clair field west of Shetland has a complex fractured reservoir estimated to have had more than 7 billion barrels of hydrocarbons originally in place. The field is operated by BP which currently holds a 28.6% interest. Production from Clair’s first phase of development began in 2005 and the field produced an average of 21,000 barrels of oil equivalent a day (boed) in 2017. A major second development phase, Clair Ridge, is expected to start production later this year with production capacity of 120,000 boed. Appraisal has also identified potential for future stages of development of Clair.
The Greater Kuparuk Area is operated by ConocoPhillips Alaska. The Greater Kuparuk Area includes the Kuparuk oilfield and the satellite fields of Tarn, Tabasco, Meltwater and West Sak. In 2017, the Greater Kuparuk Area had average daily gross oil production of approximately 108,000 barrels a day. The agreement will also include BP’s interest in the Kuparuk pipeline, which transports oil from the Greater Kuparuk Area to the inlet of the Trans-Alaska Pipeline (TAPS) at Pump Station 1.
The transaction will not affect BP’s position as operator and co-owner in the Prudhoe Bay oilfield in Alaska.
The Clair field, 47 miles (75 kilometres) west of Shetland, was discovered in 1977. The field had more than 7 billion barrels of hydrocarbons estimated originally in place but held in a highly complex and fractured reservoir.
The first phase of development of Clair began production in 2005, targeting approximately 300 million barrels of recoverable resources via the first fixed offshore facility to be installed in the West of Shetland area.
The second phase of development, Clair Ridge, is targeting a further 640 million barrels of recoverable resources. Construction of Clair Ridge’s two bridge-linked platforms was safely completed in 2016, commissioning activities are now underway and production from the project is expected to begin later in 2018. Peak production is expected to be around 120,000 boed.
The Clair partners are now evaluating a potential third phase of development of the field.
Increasing holding in core oilfield, west of Shetland in UK, and selling non-operating interest in Alaskan asset.
Buying 16.5% in Clair field from ConocoPhillips; selling interest in Greater Kuparuk Area to ConocoPhillips.
Two transactions together expected to be cash neutral for BP.The current Clair partners are: BP, operator, 28.6%; ConocoPhillips, 24%; Shell UK Limited, 28%; and Chevron North Sea Limited 19.4%.
The Kuparuk oilfield, on Alaska’s North Slope 40 miles west of Prudhoe Bay, was discovered in 1969 and began production in 1981.
Remembering Yesterday: 7-4-18
Independence Day Commentary
We remember with serious nostalgia a 1940 Cary Grant film illustrating the amazing sacrifices required to enact America’s Declaration of Independence and enforce its provisions within the colonies.
The film demonstrates that, as today, the colonist patriots had not only to fight the British army on the one hand, but deal with the “enemy within” as well. Sound familiar?
Today, following yesterday’s 2018 Independence Day celebration we feel a rising anger and deep remorse. Those feelings feed flames of amazement and disgust that some citizens today devalue America’s sacrifices for freedom. They attack our freedoms while ignorantly marching to the drumbeat of despotic socialism.
These internal enemies led by “handlers and seditionist financial contributors” abuse the society and institutions enabled by the Constitution of the United States and protected by selfless patriots produced by more than a dozen generations of our forebears.
Our readers appreciate that energy is the economic foundation of North America. But not all of our fellow citizens appreciate that only free enterprise produces sufficient energy to power our great way of life.
That explains why on this energy webpage, our readers occasionally receive messages that support our way of life. For energy supports our civilization and only a free civilization can support robust energy development.
The values of energy and our American way of life are mutually dependent — both relying on the freedom that binds us all as one.
Lest we forget.
(NGP Photo by Dave Harbour)
Today’s Relevant Energy Links Courtesy: Larry Persily, former Federal Coordinator, Alaska Gas Pipeline
(The Advocate; Baton Rouge, LA; June 29) – Almost $100 billion of liquefied natural gas projects are in various stages of construction or planning in Louisiana, representing a wave of about a dozen companies trying to cash in on global demand in the 2020s. Exactly how many projects come to pass will depend on which can land contracts and secure financing in the coming years, and whether an escalating trade war with China — perhaps the most important global market — derails the industry’s momentum.
“China is the big elephant in the room,” said Bill Rase, executive director of the Port of Lake Charles. “If China’s not happy … you might only have a couple more of these things be built.” Regardless, experts do not expect all of the 10 or so projects that have been announced will materialize. Louisiana’s access to U.S. gas production, its coastal location and its billions in tax breaks have attracted a crop of LNG mega-projects. Ahead of the proposals, Cheniere Energy is expanding its Sabine Pass terminal, and Sempra’s Cameron project is under construction in Hackberry and set to open in 2019.
In all, projects under construction or approved total $40 billion, according to Louisiana Economic Development. Another $52 billion in projects have been announced but not yet approved. So far, China has not put a retaliatory tariff on U.S. LNG, but Tulane University economics professor Eric Smith warned that may be because China is more or less forced to buy from the U.S. at the moment. Once global supply catches up, that could change. The other headwind is the steel and aluminum tariffs President Donald Trump slapped on imports. Those could spell higher costs for LNG projects, Smith said.
(Rystad Energy; July 4) – In April 2017, Qatar lifted the North Field moratorium on new gas production that had been in place since 2005, looking to boost output from the world’s largest gas field and export more LNG. The company plans to build three new liquefaction trains with a total annual capacity of 23.4 million tonnes, lifting the country’s export capacity to 100 million tonnes. The expansion comes at a time when there are several liquefaction trains in the U.S. ready to reach final investment decision.
The Qatari expansion represents a challenge for U.S. projects as it is estimated to have the lowest breakeven price of all the planned LNG export projects in the world. Rystad Energy estimates the breakeven price for the Qatari expansion at around $5.60 per million Btu (including transport to Asia), about one-third less than the breakeven price of the more competitive U.S. projects of between $7.50 and $9.10.
Qatargas signed a front-end engineering and design contract earlier this year, sending a clear signal it will go ahead with the project. Though it has not disclosed any long-term supply deals with potential buyers, China could be especially interested in signing with Qatar since U.S. supplies could eventually be subject to tariffs if the U.S.-China trade war continues to escalate. Rystad forecasts that at least 56 million tonnes of new LNG supplies will be needed by 2025; Qatar could meet 40 percent of that with its expansion.
(Sydney Morning Herald; July 4) – Japan’s Inpex Corp. has delayed gas production from its giant Ichthys field off the coast of Australia just weeks after giving assurances that output would start imminently. Inpex’s new CEO, Takayuki Ueda, did not give a timetable for when it would start producing at the $US40 billion ($A54 billion) project, located 135 miles offshore Western Australia and 510 miles southwest of Darwin. Inpex has a history of pushing back the timeline at Ichthys.
It was originally due to start production at the end of 2016, but that was pushed back to mid-2017 and then shifted to March 2018 due to delays in the installation of offshore facilities. It then pushed back its timeline to May due to poor weather and cyclones, before shifting to late September. The delays have boosted the costs of the project from its initial $US34 billion. Wood Mackenzie’s Asia Pacific director of gas and LNG research Nick Browne said the latest series of delays were always on the cards.
“A lot of people felt that the initial timeline set in May for the first LNG shipped by September was too aggressive,” Browne said. At full operation, Ichthys is expected to produce 8.9 million tonnes of LNG a year, along with about 1.7 million tonnes of liquefied petroleum gas and 100,000 barrels per day of condensate. The joint venture between Inpex — as the operator of an LNG project for the first time in the company’s history — includes partners France’s Total, CPC Corp. Taiwan, Tokyo Gas, Osaka Gas, Kansai Electric, JERA and Toho Gas.
(Reuters; July 2) – Taiwan’s CPC Corp. on July 2 announced a preliminary deal to buy liquefied natural gas from U.S. producer Cheniere Energy for 25 years, according to a statement from the Taiwanese company. CPC, a major importer of LNG, signed a heads of agreement to purchase 2 million tonnes of LNG annually from Cheniere.
The Houston-based company is gearing up to start shipments from its second U.S. export plant at Corpus Christi, Texas. The first two liquefaction trains at Corpus Christi are scheduled to start production next year. A third train is under construction. The company’s first LNG export terminal, at Sabine Pass, Louisiana, started shipping gas in February 2016. It has four trains in operation there and a fifth under construction.
(Reuters; July 2) – Japan’s JERA has bulked up into one of Asia’s biggest energy traders with its second acquisition of a key team from France’s EDF Trading — its LNG business — a deal aimed at making the Japanese utility more savvy and nimble, as well as gaining better access to European markets. The signing of the deal, which follows the purchase of EDF Trading’s coal business last year, brings a further infusion of the French company’s more aggressive trading style into JERA, a traditional power firm.
“There are no other utilities in Japan that trade both coal and LNG,” said Yuji Kakimi, president of JERA, a venture between Tokyo Electric and the Chubu Electric. “Altogether, we’re a 300-strong team whereas other Japanese utilities have just a few,” he said. That number for JERA Trading, a unit based in Singapore, represents an increase of about 100 employees. That includes 10 people from EDFT, 60 LNG-related staff in Tokyo while the rest will be a mix of current JERA employees and new hires.
Competitors say the combination of JERA, the world’s top buyer of LNG and a leading buyer of thermal coal, with EDF’s highly regarded coal and gas teams could herald big changes. “They have plentiful cash, they have global positions to allow them to move fast, and they have the personnel to act,” said a trader at a major commodity merchant. The deal allows JERA to share EDFT’s access to 15 LNG terminals in Europe that connect to gas hubs in Great Britain, France, the Netherlands, Belgium and Spain.
(Reuters; July 4) – Asian utilities are increasingly striking up European partnerships and hunting for acquisitions to hedge their large multibillion-dollar purchases of U.S. liquefied natural gas supplies. In the latest example, Japan’s JERA, the world’s largest buyer of liquefied gas, will absorb the LNG trading desk of France’s EDF Trading to gain wholesale access to European gas markets and sharpen its trading edge.
Such deals, also struck lately by Tokyo Gas and Korea Gas, give Asian giants a fallback market for U.S. supplies which they may not need and may want to sell, having rushed to commit to big chunks of U.S. liquefaction capacity in the past six years. JERA’s takeover of EDFT’s LNG trading desk allows it to gain access to 15 LNG terminals in Europe, just as shale gas producers on the U.S. East Coast ramp up exports. Europe consumes more than 19 trillion cubic feet of gas per year, mostly pipeline deliveries.
The U.S. has sold more than 40 percent of its projected output of 69 million tonnes per year from five planned LNG plants, in operation or under construction, to Asia, the bulk of which will go to Japan and South Korea. Asia’s thirst for U.S. LNG deals stems from its desire to strike relatively flexible contracts with new producers and wean itself off costly oil-linked supplies. But the rise of alternative fuels and, in Japan’s case, the potential restart of its nuclear reactor fleet, may put a brake on demand growth there.
(Petroleum Economist; June 28) – After peaking at more than 15.5 trillion cubic feet of gas per year in 2015, production in Asia is predicted to start gradually declining in the coming decade. Indonesia, Pakistan, Thailand, Bangladesh, Myanmar — and to some extent Malaysia — will see falling indigenous production from established reserve bases. By 2030, gas production in Asia is predicted at about 13.8 tcf, according to Rystad Energy, representing an annual average reduction of 0.8 percent.
The most marked drop in domestic gas production in the region is forecast in Indonesia, Southeast Asia’s largest economy. Output is forecast to fall from a peak of 2.65 tcf in 2010 to around 1.8 tcf by 2030, assuming no new investment. In recent years, falling oil prices have constrained upstream investment by Indonesia’s state-owned Pertamina — Asia’s second-largest gas producer after PetroChina. Also, a challenging regulatory environment has deterred oil and gas majors from exploration activities.
Rising energy demand means Indonesia is likely to become a net importer of gas by 2020, as it could buy more than it sells. The country started liquefied natural gas exports in 1977. At the other end of the production story is China, where output could increase from 4.236 tcf in 2016 to around 5.29 tcf by 2030, surpassing all other Asian nations. Dominant producer PetroChina has been steadily building gas production since 2004.
(Reuters; July 2) – A BP-led international consortium started its first commercial deliveries of natural gas to Turkey from Azerbaijan’s giant Shah Deniz field on June 30, BP said, part of efforts aimed at cutting Europe’s dependence on Russian energy supplies. The European Union is trying to cut its reliance on Russian gas by developing the so-called Southern Gas Corridor, which is expected to bring more gas to Europe.
Russian gas has become increasingly politicized since 2014 when Moscow annexed the Crimea peninsula. Russian gas giant Gazprom holds 34 percent of Europe’s gas market. The new supply for Europe will come from the South Caspian Sea Shah Deniz II field in Azerbaijan via the 1,150-mile Trans-Anatolian Natural Gas Pipeline through Turkey, the 302-mile South Caucasus pipeline extension through Azerbaijan and Georgia, and the 544-mile Trans-Adriatic Pipeline across Greece, Albania and Italy.
With an investment of some $28 billion, BP said the project would total at least 26 subsea wells, two bridge-linked platforms, 300 miles of subsea pipelines and flowlines, a major expansion at the Sangachal Terminal near the Azeri capital Baku, and expansion of the South Caucasus Pipeline. The Shah Deniz I field, which has been pumping since 2006, produces more than 350 bcf per year. Shah Deniz II is expected to add 560 bcf per year, with about 60 percent for Europe and 40 percent for Turkey. The Shah Deniz fields also will produce up to 120,000 barrels of condensate a day, BP said.
(Reuters; June 28) – The United States should help the natural gas industry overcome environmental challenges to new pipelines by adjusting regulations or adopting new laws favoring infrastructure, a TransCanada executive said at a gas conference in Washington, D.C., this week. Suppliers in the United States, the world’s biggest gas producer, have had a harder time getting shipments to market as more lawsuits by environmentalists, property owners and some states have tied up pipeline construction.
“It’s definitely not getting easier to build a new pipeline,” said Stanley Chapman, president of U.S. gas pipelines at TransCanada. “I’m seeing more already-approved pipeline projects that are under construction get held up by a judge in lawsuits, and this has to be addressed either by FERC or with legislation,” he said. The Federal Energy Regulatory Commission oversees pipeline construction. TransCanada owns about 30,000 miles of gas lines in the U.S., making it one of the country’s biggest operators.
In recent weeks, environmental groups have won court orders delaying construction on the Mountain Valley pipeline at several locations in West Virginia and are now seeking a court order to stop work in Virginia. Some of the most controversial projects are directed to serve eastern states and New England. “Right now, gas from the Marcellus and Utica shale is being blocked by some of our neighboring states, which cuts off our markets in New England,” said U.S. Sen. Shelley Moore Capito, a West Virginia Republican.
(Providence Journal; RI; July 3) – The $180 million natural gas liquefaction plant proposed by National Grid on the Fields Point waterfront in Providence, R.I., has cleared a key hurdle after federal regulators issued a favorable environmental assessment for the controversial project. The next step in the permitting will be a final order from the Federal Energy Regulatory Commission. The public has until July 25 to comment on the assessment, and the commission then will have 30 days for review.
If FERC grants approval, National Grid could start construction sometime next year. The U.K.-based company operates gas and electric utilities worldwide. In 2015, it proposed to build the Rhode Island plant to liquefy gas taken from a nearby pipeline, holding the LNG in a storage tank that has been used since the 1970s. The 127-foot-high tank is part of a backup system to channel gas to heating customers on the coldest days when demand is highest. The storage facility is currently supplied by truck deliveries of LNG imported from overseas to the National Grid terminal in Everett, Massachusetts.
National Grid said tapping into the pipeline that runs through Providence will ensure a more secure and potentially cheaper gas supply from U.S. shale fields. The facility would be able to liquefy and store 20 million cubic feet of gas per day. Opponents have objected and have said it means increasing Rhode Island’s dependence on shale gas recovered through hydraulic fracturing that can taint drinking water supplies, lead to leaks of methane, a potent greenhouse gas, and cause other environmental damage.
(The Canadian Press; June 29) – Canada’s oil patch is eagerly anticipating higher prices and profits after the Minnesota Public Utilities Commission on June 28 approved Calgary-based Enbridge’s $9 billion project to upgrade its deteriorating Line 3 oil line through the state. The replacement pipe is to restore Line 3’s capacity to 760,000 barrels per day, adding 375,000 barrels of export capacity into the U.S. when it comes on stream in late 2019 or early 2020. The line runs from Alberta to a pipeline hub in northern Wisconsin.
The extra capacity is expected to help relieve a transportation bottleneck that has increased the discount on Canadian oil prices versus U.S. benchmarks. Canada will still need the Trans Mountain pipeline expansion to the West Coast and the Keystone XL pipeline into the U.S., said Chris Bloomer, CEO of the Canadian Energy Pipeline Association. “From our perspective, this was the best news that the Canadian oil and gas industry has received for a long time,” said analysts at Desjardins Capital Markets.
Construction of the pipeline is crucial to ensure access to the U.S. Midwest, which imported 2.3 million barrels per day of Canadian crude in 2017, said Nancy Berard-Brown, manager of oil markets and transportation for the Canadian Association of Petroleum Producers. The company estimates the pipeline will be in service in the second half of 2019, although analysts cautioned it may take until the first quarter of 2020 if substantial civil disobedience delays construction.
(Reuters; July 2) – Plans to import liquefied natural gas to Australia, the world’s second largest LNG exporter, could help cap soaring local gas prices, although the economics might not work, the Australian government said July 2. Over the past two years, four projects to import LNG have been proposed following the opening of three new LNG export plants on Australia’s east coast that have sucked gas out of the southeastern market and nearly tripled wholesale gas prices.
Australia’s energy market operator recently wound back a forecast for a near-term deficit, saying it no longer expects a gas shortfall in southeastern Australia before 2030 due to new production and government pressure on exporters to boost local supply. But LNG import plans are advancing anyway and could still be justified as gas produced in Queensland state is expensive, piping it south to where the gas is needed is costly, and imported LNG from the spot market could be cheaper, the government said in a report.
The report said the main challenges to imports will be to find cheap LNG beyond 2022, when global demand is expected to start outstripping supply, and to line up enough local gas demand to underpin import projects. The report found that U.S. gas at around current prices could be delivered to Asia for $8 per million Btu, or A$10.10 per gigajoule, roughly in line with current gas prices for industrial users. However, regasification, including capital costs, would add between A$1.30 to A$2.60 per GJ to the cost.
(Reuters; June 30) – A Swedish arbitration court ruled that Poland’s dominant gas company, PGNiG, can demand a lower price for the gas it buys from Russia’s Gazprom, PGNiG said June 30. PGNiG buys from Gazprom most of the gas it resells, and it said it pays more than its western European peers. New prices, still to be determined by the arbitrators, should apply retroactively from Nov. 1, 2014, when PGNiG asked that the prices be revised, PGNiG said in a statement.
PGNiG filed for arbitration of its complaints in May 2015 to the Arbitration Institute of the Stockholm Chamber of Commerce, a neutral body that resolves international commercial disputes. The arbitrators initially agreed with PGNiG. The decision does not rule out PGNiG reaching agreement with Gazprom over pricing, the company said.
Poland wants to reduce its reliance on Russian gas and does not plan to extend its deal with Gazprom when it expires in 2022. Under the contract’s take-or-pay formula, PGNiG has to buy 300 billion cubic feet of gas annually. Separate from its arbitration case, PGNiG has been buying more liquefied natural gas to replace gas from Russia. Poland also plans to build a pipeline to Norway, which would give it access to North Sea gas.
Dave Harbour, publisher of Northern Gas Pipelines, is a former Chairman of the Regulatory Commission of Alaska, a Commissioner Emeritus of NARUC, NARUC's Official Representative to IOGCC and Vice Chairman of NARUC's Gas Committee. He served as Gas Committee Chairman of the Western Conference of Public Service Commissioners. He also served as commissioner of the Anchorage Bicentennial Commission and the Anchorage Heritage Land Bank Commission.He earned a Bachelor of Arts Degree: English, at Colorado State University, a Master of Science Degree: Communications-Journalism at Murray State University and graduated from Utility Regulatory School for Commissioners at Michigan State University. He served as a Vice President for Communications and Public Affairs at Alaska Pacific University, taught bank marketing classes at the University of Alaska and was an English teacher at Los Alamos High School.Harbour served in ranks of Private - Captain during a 4-year assignment with the Army in Korea, Idaho, Georgia and Fort Meade and received the Meritorious Service Medal among other commendations.Harbour is also a past Chairman of the Alaska Council on Economic Education, the Alaska Oil & Gas Association Government Affairs Committee, the Anchorage Chamber of Commerce, the Export Council of Alaska and the Department of Commerce's District Export Council. He is a past President of the Alaska Press Club, American Bald Eagle Foundation, Consumer Energy Alliance-Alaska and Common Sense for Alaska.Harbour was instrumental in founding the American Bald Eagle Research Institute (UAS), the Alaska Support Industry Alliance, the Downtown Anchorage Business Partnership, and Arctic Power.He also served as CEO of several small Alaska organizations, including the Anchorage Parking Authority and Action Security, Inc. Harbour is also Chairman Emeritus of the Alaska Oil & Gas Congress.Harbour's wife, Nancy, is a professional, performing arts administrator and his three boys, Todd, Benjamin and William work in the fields of environmental management, energy marketing and medicine.