Cautionary note: The email alert we issued today indicated that we would have more to say in coming weeks about these Arctic OCS regulations.  Our initial scanning of the regs today, did not lead us to immediate judgment.  We deeply respect the work of Congressman Bishop (below) and his predecessor, Doc Hastings.  However, on this issue of the Arctic OCS regs, study is required before reaching final conclusions.  A respected friend with one of the regulatory agencies wrote us with this caution: “ Dave, Dave, Dave: safe, effective, and responsible exploration of Arctic OCS oil and gas resources “.  The regs may, after study, be determined to be relatively benign, but we would also note that upcoming issuance of a final, 2017-2022 Five Year OCS lease sale plan could make the regs moot should they prohibit Arctic OCS leasing for the foreseeable future.  (Note:  we always appreciate words of wisdom from our professional readers.  Just as we abhor an overreaching federal bureaucracy, so do we abhor and try to avoid a ‘rush to judgment’ on every federal policy announcement.)  -dh

Today, the U.S. Department of the Interior (DOI) released the finalized safety regulations for Arctic offshore drilling for both the Bureau of Ocean Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE). Chairman Rob Bishop (R-UT) released the following statement:

This President continually gives Putin the upper hand. While other nations develop their offshore Arctic resources, this Administration is holding our nation back. This was never about responsible development, it was about keeping the Arctic frozen from development. The rule is based on the fallacy that it is technologically unsafe and economically unviable to develop the Arctic. The Obama Administration has used every tool at its disposal to deny Native Alaskans economic growth opportunities, undermine American’s energy strength and risk national security.”

On June 16, 2015, the Subcommittee on Energy and Mineral Resources held an oversight hearing that discussed a National Petroleum Council study on Arctic energy development. The study, which included a consortium of experts, academia and environmental groups, found that most Arctic offshore resources can be safely developed using existing, field-proven technology.

Other reports:  The Hill

TODAY’S Alaska Support Industry Observation

Our friends at the Alaska Oil & Gas Association (AOGA) issued a press release today on State of Alaska data showing a three percent increase in oil production during the last fiscal year. This is great news for Alaska, however recent legislative action jeopardizes our ability to continue this trend.

“State of Alaska Division of Oil and Gas preliminary data shows total production in FY (fiscal year) 2015 was 168.143 million barrels. Total production in FY 16 is 173.563 million barrels (estimate-extrapolating through June 2016), or an increase for FY 16 of 3.22 percent. ( All oil produced off the North Slope generates royalty payments, which fuels the corpus of the Permanent Fund.”  To read the entire release on AOGA’s website, click here.

AND this…from Today’s Alliance Headlamp commentary

The Fairbanks Daily News Miner ran an editorial arguing that theNenana basin may be the best bet to deliver gas to residents cheaply and quickly for the Interior Energy Project. According to the piece, “Should commercial gas be found in the Nenana basin, it would help tremendously with one of the project’s biggest obstacles: low-cost transportation. Being far nearer at hand than gas from either Cook Inlet or the North Slope, costs to deliver the gas to Fairbanks would be less, giving the project a better chance at coming in at or below its price target of $15 per thousand cubic feet — the equivalent of heating oil at $2 per gallon.”  Headlamp would note that the state’s oil and gas tax credits had helped with this project – prior to the passage of HB 247. 

Not making the grade. According to a recent Alaska Dispatch News poll, roughly half the 670 respondents handed out grades of D’s and F’s to the state’s Democratic and Republican lawmakers, with Gov. Bill Walker, an independent, earning just a C average. Fifty-five percent of respondents disagreed with Walker’s proposal to restructure the Permanent Fund to help balance the budget, while 45 percent said the state’s tax structure asks too little from oil companies. Headlamp would have to give that 45% an F on their understanding of the current tax structure and the instability created by constantly changing the tax system. 

Edison Chouest Offshore will be adding new vessels to its fleet when it takes over the oil tanker escort and spill response duties out of Valdez in July 2018. Louisiana-based Edison Chouest announced in early June that it was selected by Alyeska to provide tanker escort and spill response services in Prince William Sound. The company will take over for Crowley Marine Services after a detailed two-year transition process. Linda Leary, president of Edison Chouest Alaska subsidiary Fairweather LLC, wrote in response to questions from the Journal that the maritime services provider parent company plans to take advantage of its in-house shipbuilding capabilities to execute its 10-year ship escort-response vessel system, or SERVS, contract with Alyeska  Pipeline Service Co.

Furie Senior Vice President Bruce Webb said in an interviewthe company plans to re-enter the KLU-4 well roughly six miles north of the Julius R platform the company installed last year above its natural gas producing wells. “We know there’s gas there for sure; we’ve drilled through some gas and we see the gas on the seismic and on the seismic it appears to be a pretty large oil reservoir, but again, you don’t know for sure until you drill into it,” he said. “It could be really good sandstone with water.” The company once intended to drill farther, into the Jurassic formation, but expiration of the state tax credit for drilling with a jack-up rig in July caused Furie to back off on the extra drilling, Webb added.

AND…today’s Oil & Gas news briefs from Larry Persily, of particular interest to our readers

Government bank in Japan helps finance Indonesia LNG expansion

(Nikkei Asian Review; July 5) – The Japan Bank for International Cooperation is providing about 120 billion yen ($1.16 billion) in financing for expansion of the Tangguh liquefied natural gas plant in Indonesia. The 7-year-old plant is owned by BP and partners from Japan and China. The bank loan is to a consortium of Japanese companies. The government-owned financial institution inked the contract June 30 with a joint-venture of partners including Mitsubishi, Inpex and a member of JX Holdings.

The project will boost annual output capacity at the plant by 50 percent to about 11 million metric tons. The $8 billion expansion is scheduled for completion in 2020. Most of the expanded LNG capacity is under contract to an Indonesian utility, with about 25 percent of the expansion (1 million tons a year) under contract for delivery to Kansai Electric Power. JBIC last lent more than 100 billion yen for a single energy project in November 2014. Other banks are leaning toward co-financing the Tangguh undertaking.

India’s LNG imports expected to double in 4 years, Wood Mac says

(Bloomberg; July 4) – India’s burgeoning demand for liquefied natural gas is dictating how many tankers make it to Europe, the world’s dumping ground for the fuel. LNG imports to India jumped 43 percent in May from a year earlier, a contrast to western Europe, where shipments have stagnated over the past three months. The world’s second-most populous nation after China is expected to double its LNG intake over the next four years, according to energy consultants Wood Mackenzie.

India overtook South Korea as the second-biggest buyer of spot and short-term LNG cargoes after prices crashed about 65 percent in the past two years, spurring demand for the cleaner fuel from India’s fertilizer producers to power plants. For a supplier, having a closer market helps. It takes three days to ship LNG to western India from Qatar, the world’s biggest producer of the fuel, compared with two weeks to get it from Qatar to the U.K. where prices are lower.

India gets the fuel from Qatar at about $5 per million Btu, according to Petronet LNG, India’s biggest importer. That compares with $4.37 on average at Britain’s National Balancing Point trading hub in the second quarter, data from the ICE Futures Europe exchange show. In May, India purchased about 75 billion cubic feet of gas as LNG. “We have seen demand elasticity in India and it’s starting to stretch regas capacity,” said Noel Tomnay, vice president of global gas and LNG research at Wood Mackenzie.

Qatari LNG exports to India, Pakistan up 50% so far this year

(Platts; July 6) – The amount of LNG delivered to South Asia (India and Pakistan) from Qatar during the first half of the year climbed almost 50 percent year on year, taking advantage of weaker demand from East Asia (Singapore, Malaysia, Taiwan, Thailand, Japan, South Korea and China) and higher Qatari output, data from Eclipse Energy, an analytics unit of S&P Global Platts, showed July 5.

Qatari LNG volume deliveries to South Asia hit 7.14 million metric tons January-June, up 46 percent in comparison with the first six months of last year. Increases in deliveries from the world’s largest LNG-exporting country were split between India and Pakistan at 6 million tons and 1.1 million tons, respectively, for the first six months of 2016. In India, this was largely driven by a renegotiated supply contract between Petronet, the country’s largest gas importer, and Qatar’s RasGas, resulting in much lower prices.

Similarly, the uptick in deliveries to Pakistan was attributable to a new 15-year agreement with Qatar for up to 3.75 million tons per year that was singed in February. Deliveries from the contract started in March 2016. At the same time, East Asian demand for Qatari LNG fell 13 percent year on year, dropping from 20.9 million tons in the first half of 2015 to 18.1 million in the first half of 2016.

Exxon, Qatar reportedly considering a stake in Mozambique gas fields

(Bloomberg; July 6) – ExxonMobil and Qatar Petroleum have teamed up to look at energy assets in Mozambique, home to some of the biggest natural gas discoveries in a generation, according to four people with knowledge of their plans. The companies are considering buying stakes in gas fields owned by Anadarko and Italy’s Eni, the sources said, asking not to be identified because the matter is confidential. No final agreement has been reached, the sources said.

Mozambique’s discoveries in the Rovuma Basin off its northern coast have attracted oil companies from Europe, the U.S. and China as the southern African country plans one of the world’s largest liquefied natural gas projects. Investment from Exxon and state-owned Qatar Petroleum, which have partnered in joint ventures for at least 15 years, would bring much needed funds for development, not to mention a tax revenue windfall to a nation grappling with a deepening debt crisis.

Exxon, Eni and Anadarko declined to comment. Qatar Petroleum did not respond to a call or e-mail. Anadarko operates in Area 1 of the Rovuma Basin, while Eni is in Area 4. Both have plans to export the gas as LNG, though neither has reached a final investment decision. Exxon has already established a presence in Mozambique after winning three offshore exploration licenses in October for blocks to the south of the Anadarko and Eni finds.

Canada’s natural gas future depends on LNG exports, report says

(Calgary Herald columnist; July 6) – Canadian gas producers have been battered by relentless headwinds in recent years and the challenges look daunting. But even with the problems created by low prices, shrinking exports, massive production increases in the U.S. and depressed drilling activity at home, there are slivers of hope on the horizon — if the sector can get through the gale. A report by the Canadian Energy Research Institute predicts gas production and prices are likely to rise over the next two decades.

Demand inside Canada will continue to grow. The country also has the potential to remain a net exporter of gas throughout the next 20 years — although Western Canadian pipeline exports to the U.S. could fall to one billion cubic feet per day by 2020, a far cry from levels topping 10 bcf seen a decade ago. It’s just that the future will be a lot brighter — and more certain — if Canada finally approves any of the liquefied natural gas export projects proposed for the country’s Pacific coast.

“We’ve come to a significant crossroads,” said Dinara Millington, CERI’s vice president of research. “Do we want Canada to be an international player in the LNG game or not? It’s pretty clear where the industry stands. …It’s not quite clear where the governments are.” If government and corporate sponsors approve LNG export plants, CERI projects an increase in gas exports of 4 billion cubic feet a day. If it doesn’t happen, the idea of ramping up production won’t materialize and Canadian gas output will stagnate or dip.

South Korea plans to shut down 10 older coal-fired power plants

(Reuters; July 6) – South Korea plans to shut 10 aging coal-fired power plants by 2025, as Asia’s fourth-largest economy seeks to cut its reliance on dirtier fuels after a pledge at last year’s Paris climate summit to reduce greenhouse-gas emissions. Coal accounts for 40 percent of Korea’s electricity supplies. In a tilt toward cleaner fuels, Seoul recently said it was targeting $37 billion in renewable energy investment by 2020. Closing the coal plants could lower fine-dust levels 24 percent by 2030 from 2015 levels.

“In response to growing concerns over fine dusts, we will lower the share of coal power by shutting down old coal-fired power plants and restricting to add new coal-fired power plants in the future,” the energy ministry said in a statement. South Korea is still committed to building 20 new coal-fired plants by 2022, but no additional plants would be considered in a new power plan next year, the ministry said.

Energy minister Joo Hyung-hwan said the percentage of total installed power capacity from coal was expected to edge down to 26.2 percent by 2029 from 28 percent in 2015. “The shutdown of 10 coal power plants will not affect the country’s power supply as we can replace them with alternative energy like biomass and renewables gradually,” said Yoon Jong-Keun, president of Korea Southern Power Co. South Korea generates 30 percent of its electricity from nuclear and 25 percent from liquefied natural gas.

China urged to step up replacement of coal-fired power plants

(Bloomberg; July 5) – China is being urged by academics to step up its efforts to replace coal with cleaner energy to fight air pollution, with the group saying some parts of the country should use natural gas in power generation. The nation should actively develop renewable energy, nuclear power and natural gas, while at the same time curbing an increase in coal use, according to an assessment of an air-pollution prevention plan conducted by 50 academics from the Chinese Academy of Engineering.

As part of the effort, natural gas supplies should be increased to Beijing, Tianjin and the province of Hebei to help replace coal with the cleaner fuel in the production of power and other industrial uses, according to the statement. Four districts in Beijing that still rely on coal-fired boilers for winter heating should phase out the fuel and use natural gas instead, it said.

Though the concentration of pollutants in Chinese cities has fallen since 2013, heavy smog in winter remains prominent, according to the report. Public anger has prompted the government to issue more measures to tackle pollution. “The progress of China’s key regions in adjusting their energy structure is far from sufficient,” Dong Liansai, a Greenpeace East Asia climate and energy campaigner, said in an e-mailed statement.

Britain will be more dependent on gas, electricity imports, report says

(Bloomberg; July 4) – Britain will depend on more imported natural gas and electricity over the next 14 years even as demand is set to shrink, according to the country’s network operator. Britain’s gas imports will rise as much as 38 percent by 2030 with the bulk coming from liquefied natural gas and also pipeline supplies from Russia, National Grid said in its Future Energy Scenarios report. The U.K. will get more electricity from its neighbors amid a fivefold boost in the capacity of power cables linked to other nations.

The U.K.’s National Grid forecasts 5 gigawatts of fossil-fueled power plants — enough to power 10 million homes — will shut down this year, crowded out of the generation mix by renewables as the U.K. reduces carbon emissions from its energy supply. Government decisions to cut wind and solar subsidies and end green measures for homes have hurt investor confidence, delaying spending on new plants, lawmakers said earlier this year, creating an opening for more electricity imports.

“The decarbonization agenda is driving significant changes to the energy supply market,” National Grid said in the report. As to the gas that the nation does need, due to declining North Sea production Britain met about 58 percent of its gas use with imports in 2015.

U.S. propane exports continue to climb, setting new records

(Wall Street Journal; July 5) – The U.S. is exporting record volumes of propane, another way in which the shale boom has made the nation a dominant force in the global energy trade. Foreign sales are surging as U.S. producers capitalize on higher prices overseas. That in turn is causing U.S. prices to rise. In a first, U.S. oil-and-gas companies are on track this year to export more propane than the next four largest exporters combined — Qatar, Saudi Arabia, Algeria and Nigeria — according to analytics firm IHS.

Propane exports hit an all-time high of 884,000 barrels a day in February, according to the U.S. Energy Information Administration. Platts Analytics, an energy data provider, projects that a new record was set in May, for which government data aren’t yet available. The exports have been enabled by a new network of pipelines, shipping terminals and tankers that doubled capacity from a year ago.

Propane, a natural gas liquid, is a byproduct of gas drilling and refining crude. The fuel came up from shale wells in such overwhelming supply that producers sometimes had to pay customers to take it off their hands. After the shale boom made propane more plentiful, exports became a widely sought solution because it is much easier to bottle and ship than other fuels. About half of all U.S. exports wind up in Latin America, while the rest goes to northwest Europe and Asian markets.

Hot start to summer pushes U.S. natural gas futures toward $3

(Bloomberg; July 5) – A blistering start to summer is helping put U.S. natural gas futures on course for the biggest gain in eight years. Gas has surged 17 percent this year, rebounding from a 17-year low. Drillers, burned by earlier declines, are refilling storage at half last year’s pace as extreme heat boosts the use of air conditioners, increasing gas demand at power plants. By November, storage volumes will probably drop below the five-year average, the benchmark for normal levels, for the first time in 13 months.

Just four months ago, gas plunged after the warmest winter on record left the market with a glut large enough to last through the year. Instead, hot weather and a slowdown in production are eating at the surplus, signaling an era of higher prices as gas exports rise and electricity generation trims excess supply. “We’re moving toward a potentially serious deficit in the supply-demand balance for this coming winter,” said Andrew Weissman, CEO of EBW Analytics Group, a Washington-based energy analyst.

Gas inventories were 25 percent above the five-year average in late June, down from 54 percent in April. An extended slide in production would erase the surplus by the end of the year, leaving stockpiles at a deficit to normal levels and pushing prices to $3 this month, according to EBW Analytics and Again Capital. “If the weather continues to be hot, we’ll start the winter with below-average supply. Gas has become the primary fuel for power generation,” said Phil Flynn, an analyst at Price Futures Group in Chicago.

Chevron, ExxonMobil commit to $37 billion oil project in Kazakhstan

(Wall Street Journal; July 5) – There are signs the deep freeze in oil-industry spending is beginning to thaw. Chevron, ExxonMobil and their Kazakhstan and Russia partners July 5 committed to a $37 billion oil expansion project in Kazakhstan — one of the biggest investments in new barrels since oil prices collapsed two years ago. And last week, BP said it was expanding a plant to liquefy natural gas at its Tangguh project in Indonesia. That investment is around $8 billion, according to a person familiar with the matter.

So far this year, energy companies have taken the plunge on eight expensive developments, according to Houston energy investment bank Tudor Pickering Holt & Co. And more are expected this year, the bank said. In 2015, just four such projects went forward. BP announced in June that it is fast-tracking a major offshore gas discovery in Egypt. Earlier this year, Italy’s Eni sanctioned development of its massive offshore Zohr gas field in Egypt where initial investment is estimated at about $4 billion.

The announcements come as the industry appears to be starting to climb out of its hole after oil prices collapsed from $115 a barrel in mid-2014 to $27 in January. The rout has forced producers big and small to cut jobs and reduce spending on new developments and exploration in efforts to cut costs. With those lower costs and prices rising to more than $50 a barrel, producers are taking a new look at projects that had been shelved.

Kazakhstan is the first investment of over $10 billion this year, said Jefferies senior oil analyst Jason Gammel. “It’s a reflection of the companies having got their cash cycles under control.” First production from the expansion is due in 2022, taking the field up to 1 million barrels of oil equivalent a day from around 800,000 barrels currently.

B.C. oil field contractors losing out to Alberta competitors

(Dawson Creek Mirror; BC; June 29) – Eighty percent of rigs sitting idle. A 50 percent drop in the number of wells drilled in British Columbia. A flood of labor coming over the Alberta border to B.C. New statistics from energy regulators and industry groups are shedding light on the grim reality that B.C.’s oil patch faced in the first half of 2016. Upstream activity continues to scrape bottom after a hard 2015, while an industry group says B.C. oil field businesses are being cut out by desperate competitors from Alberta.

The industry has been hit by a drop in oil and gas prices that began in late 2014, brought on by a global supply glut and economic slowdown in Asia. Those headwinds have left a big question mark over B.C.’s proposed liquefied natural gas industry, which could shore up the province’s oil and gas sector by providing access to the world market. Energy Services BC, a Fort St. John-based advocacy group for the oil and gas service sector, said its numbers have dwindled with the downturn.

The group peaked at 300 members. “Today, we’ve got 75,” President Dave Turchanski said. The industry is being pounded by Alberta contractors able to underbid their B.C. competitors due to tax advantages, he said. “A lot of times when Alberta (contractors) come in, they bring their own fuel in. They’re not paying the

[B.C.] carbon tax on their fuels or oil. When you start adding that all together you’re looking at a 9.5 to 11 percent difference. That’s going to make the difference in whether a guy gets the bid or not.”