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Shell has agreed to acquire BP's 27.5% working interest in the Shearwater field in the UK North Sea, negating the planned sale of the stake to Tailwind Energy. Financial terms of the deal were not disclosed. As operator of the field, Shell had a right of first refusal over any sale of BP's interest. BP had previously attempted to offload its Shearwater interest at least twice. The first time, in 2020, it struck a deal with Premier Oil as part of an overall asset package valued at $625 million.
Premier Oil has agreed to acquire interests in various UK North Sea projects from BP and Dana, spending more than $800 million in the process. Among these acquisitions are the Andrew and Shearwater areas in the UK Central North Sea, which includes the Andrew, Arundel, Cyrus, Farragon, and Kinnoull fields, as well as BP's non-operated interest in and relating to the Shearwater high pressure, high temperature gas condensate field. The five fields in the Andrew area all produce through the Andrew platform, which is located approximately 140 mi northeast of Aberdeen, Scotland. BP holds operated stakes between 50% and 100% in each of the fields. Premier said it intends to assume operatorship of the area upon completion of the deal, subject to customary joint venture and regulatory approvals.
BP has agreed to sell several properties in the UK North Sea to Premier Oil for $625 million. The assets set to change hands include the BP-operated Andrew area and its non-operating interest in the Shearwater field. The deal, expected to close later this year, is part of BP's plan to divest $10 billion by the end of 2020. "BP has been reshaping its portfolio in the North Sea to focus on core growth areas, including the Clair, Quad 204, and ETAP hubs," said Ariel Flores, the North Sea regional president at BP. "We're adding advantaged production to our hubs through the Alligin, Vorlich, and Seagull tieback projects." BP operates five fields in the Andrew area: Andrew (62.75%);
E&P Notes Guyana Hits New Milestones First oil has begun flowing ahead of schedule from the Stabroek block offshore Guyana, a milestone from one of the world’s most promising basins. The production occurred fewer than 5 years after the first discovery of hydrocarbons and underscores Guyana’s emergence as a major oil producer. Output from the first phase of the Liza field soon will reach 120,000 B/D, with the first cargo of oil set to be sold early in 2020, according to operator ExxonMobil. “This historic milestone to start oil production safely and on schedule demonstrates ExxonMobil’s commitment to quality and leadership in project execution,” ExxonMobil Chairman and CEO Darren Woods said in a statement. “We are proud of our work with the Guyanese people and government to realize our shared long-term vision of responsible resource development that maximizes benefits for all.” Tackling Carbon Emissions on a Grassroots Level As industries and governments struggle on a global scale to stop carbon emissions and accelerate progress toward the 2°C path set out in the Paris Agreement, efforts are also growing to tackle emissions and climate change on a grassroots level. In Alberta, for example, a $35-million challenge to turn CO2 emissions from a waste stream into valuable products for the Canadian province has led to the commercialization of two new technologies that could deliver greenhouse gas (GHG) reductions of almost 2 million metric tons per year by 2030—that’s equal to GHG emissions from 424,628 passenger vehicles driven for one year or carbon sequestered more than 33 million tree seedlings grown for 10 years. As co-winners of Emission Reductions Alberta’s (ERA) Grand Challenge: Innovative Carbon Uses, Mangrove Water Technologies and CarbonCure Technologies each received $5 million to help commercialize their technologies to capture and use CO2 to deliver environmental and economic benefits in Alberta and around the world. The two companies were the final winners of ERA’s 5-year, $35-million challenge, which was designed to accelerate unique, promising, and impactful technologies to convert CO2 emissions into new carbon-based products and markets. Shell’s Well Pad of the Future Is Open for Business A defining feature of the oil and gas industry’s ongoing digital transformation is that it has never been done before. That means every company is allowed to have a different playbook on how to carry it out. For its unconventional assets, Shell’s plan was to build a team to seek out and mold emerging innovations to match the rigorous needs of its production assets. Launched in 2017, this program is known as iShale and its first major test is underway in the Permian Basin where the international major operates nearly 500 oil wells. In November, Shell brought online two pads with a total of eight wells at the East Slash Ranch in west Texas. Each are connected to multiphase gathering systems and a “mini-modular” processing facility. The multi-well project represents a “kitchen sink” approach to digital technologies and aims to find out if combining several of the latest innovations all at once will reduce over all development costs, cycle times, and carbon footprints. Devon Sells Barnett Asset to Thai Venture Firm for $770 Million After spending most of the year looking for a buyer, Devon Energy announced this week the sale of its entire stake in the Barnett Shale to Banpu Kalnin Ventures (BKV) for $770 million. “Devon’s transformation to a US oil growth business is now complete,” said Dave Hager, the president and chief executive of Devon. He added in a statement that the divesture of the north Texas property combined with its earlier sale of its Canadian assets has netted $3.6 billion. “The Barnett Shale has been a cornerstone asset for Devon over the past two decades,” said Hager. “With this change in ownership, it is great to see our talented and innovative employees supporting this high-quality gas asset transition to a world-class company like Banpu.” Total to Gain Blocks, Extend Production Licenses Offshore Angola Total has agreed to acquire interests in two blocks in the offshore Kwanza Basin from Angola’s state-owned Sonangol and has received an extension on its offshore Block 17 production licenses. In the acquisition from Sonangol, the French major will add a 50% interest in Block 20/11, located in 300–1,700 m of water in the central Kwanza Basin. Partners Sonangol and BP hold 20% and 30% of the block, respectively. Total will also add an 80% interest in Block 21/09, located in 1,600–1,800 m of water in the south-central Kwanza Basin. Sonangol holds the remaining interest. Four discoveries have been made on the blocks, where Total envisions a new development hub and has committed to explore for additional resources. As part of the agreement, Total will become development operator before establishing an operating company with Sonangol 3 years after the start of production. BP Confirms Further Gas Potential Offshore Mauritania, Senegal BP said its recent three-well drilling campaign offshore Mauritania and Senegal has further confirmed the world-class scale of the gas resource in the region. Three appraisal wells drilled this year—GTA-1, Yakaar-2, and Orca-1—targeted nine hydrocarbon-bearing zones, encountering gas in high quality reservoirs in all zones and yielding a combined 160 m of net pay. The campaign was completed 40 days ahead of schedule and $30 million under budget, said the British major. Most recently, the Orca-1 well on Block C8 offshore Mauritania, encountered all five of the gas sands originally targeted. The well was then further deepened to reach an additional target, which also encountered gas. Superior Energy Becomes Latest Service Firm to Abandon Pressure Pumping Superior Energy Services has announced plans to eliminate its entire US pressure pumping business unit, becoming the second oil field service firm to make such a decision this month. In November, Superior laid off more than 100 people in the Permian Basin and is anticipating a write-down of $45 million and will use any proceeds from asset sales to pay down debts. The Houston-based service provider has an international footprint and also offers drilling and production product lines. A week ago, smaller rival Basic Energy Services said it hoped to raise between $30–45 million by selling off most of its pressure pumping equipment. US Sets New Records for Proved Oil and Gas Reserves The US in 2018 posted record highs in proved reserves for crude oil and natural gas, which were respectively up 12% and 9% year-over-year, according to a report from the US Energy Information Administration (EIA). The increases were driven by strong oil and gas prices, the agency said. Proved oil reserves totaled 43.8 billion bbl at year end, topping the previous year’s record, as US crude and lease condensate production surged 17% year-over-year. The annual average spot price for West Texas Intermediate crude at the Cushing, Oklahoma, storage hub increased 29% in 2018 to $65.66. Producers in Texas added 2.3 billion bbl of crude and lease condensate proved reserves, the largest net increase of all states in 2018, thanks to higher prices and development in the Permian Basin. New Mexico also benefited from Permian drilling, which helped give the state an additional 750 million bbl in crude and lease condensate proved reserves. North Dakota ranked third among the states, adding 422 million bbl. BP Makes $625 Million Exit From North Sea Assets. BP has agreed to sell several properties in the UK North Sea to Premier Oil for $625 million. The assets set to change hands include the BP-operated Andrew area and its non-operating interest in the Shearwater field. The deal, expected to close later this year, is part of BP’s plan to divest $10 billion by the end of 2020. “BP has been reshaping its portfolio in the North Sea to focus on core growth areas, including the Clair, Quad 204, and ETAP hubs,” said Ariel Flores, the North Sea regional president at BP. “We’re adding advantaged production to our hubs through the Alligin, Vorlich, and Seagull tieback projects.”
Gas exploration activity in North America looks like it is in the doldrums. In the past 12 months, gas-directed North American rig counts have fallen by almost half. This is easy to understand. Since the beginning of 2010, front-month gas futures prices have fallen from USD 5.60/MMBtu to their current level of USD 3.60/MMBtu. I have a bullish view on the long-term future of natural gas. When accounting for all of the upside influences—environmental imperatives, relentless demand growth in the developing world, the potential of the domestic power sector, revitalization of the US industrial base, and downstream innovations such as gas to liquids (GTLs)—the picture looks positive. At the same time, I have a firm belief that continuing innovation will drive efficiency, making gas an even more attractive alternative and leading to more exploration and development. These indicators lead me to believe a second wave in the development of the North American gas business is on the way.
The first wave has been quite a ride. Only a few years ago, gas industry pundits assumed that new gas demand could only be met with imports. An entire subindustry was developed around the regasification, storage, and transport to market of imported liquefied natural gas (LNG). Today, LNG regasification facilities are largely idle. Instead of increasing, gas imports have fallen dramatically—from 12.6 Bcf/D in 2007 to less than 9 Bcf/D in the most recent 12 months.
Although gas production has increased dramatically, from just under 55 Bcf/D in 2007 to a current rate of 69 Bcf/D, the increases in production have been absorbed incrementally, without long-term structural adjustments in the US energy economy or significant investments in infrastructure. Existing gas plants displacing coal in the power sector and reductions in imports have absorbed more than 70% of the increase in gas production.
The United States is still a net gas importer, but the industry is now focused on developing export markets. Those markets are there. Demand growth in China is almost certain for a generation. If Japan follows up on its commitment to step away from nuclear power, new supplies will need to be found there.
Exporting gas will require us to adopt workable regulations, develop infrastructure, and change a mind-set. The United States is accustomed to thinking as an energy importer. As new sources are developed, we tend to guard them jealously and reserve them for domestic use. The Federal Energy Regulatory Commission approves the construction of LNG liquefaction facilities and the Department of Energy grants export licenses based on a “public interest” standard.