September 2017, Vol. 244, No. 9

In The News

In the News

Did BP Just Unlock a New Major Shale Gas Basin?

BP made a potentially groundbreaking discovery in New Mexico, which could open up a new area for shale gas development. The oil major was drilling in a little-known area in northern New Mexico, in a place called the Mancos Shale. BP reported huge figures from the shale gas well, suggesting the Mancos could provide a massive new source of U.S. shale gas.

The initial 30-day production rates of the new well hit 12.9 MMcf/d, a figure that tops horizontal wells in the highly prolific Eagle Ford shale, which often see wells producing 8-12 MMcf/d. The production figures are the highest in 14 years within the San Juan Basin, which encompasses southwest Colorado and northeast New Mexico, and includes the Mancos Shale.

“We are delighted with the initial production rate of this well,” said Dave Lawler, CEO of BP’s U.S. Lower 48 onshore business. “This result supports our strategic view that significant resource potential exists in the San Juan Basin, and gives us confidence to pursue additional development of the Mancos Shale, which we believe could become one of the leading shale plays in the U.S.” BP plans on relocating its U.S. headquarters to Denver, a sign of how important the British oil company views the Rocky Mountain region.

A report in 2016 from the U.S. Geological Survey estimates that the Mancos Shale holds 66.3 Tcf of natural gas, enough to rank the Mancos as the second-largest shale play in the country, just behind the Marcellus. – Nick Cunningham,

Fitch: North American Midstream Energy Facing Raised Volume Risks

Renewed pressure on domestic energy production budgets has the potential to weigh on U.S. midstream oil and gas volumes in the second half of 2017, reports Fitch Ratings. Volumetric risk remains the primary concern for gathering and processing operators, particularly with oil prices still lingering in the $45-50 per barrel range.

Recent meetings and roundtables with investors have focused on Fitch’s stable outlook for the midstream space. Positive trends in capital market access and liquidity have supported the midstream industry outlook. Still, higher cost of equity capital could raise leverage for some issuers, and credit metrics are stressed for some names. Volume pressure in second-half 2017 and 2018 could erode metrics further.

Geographic concentration is an important factor influencing midstream issuers’ operating outlooks. Outside of the more attractive Permian, SCOOP/STACK and Marcellus/Utica production basins, U.S. midstream issuers expect to see lower volumes over the near term.

The Permian region is the clear winner in terms of growth potential. It continues to show volume increases in both crude and natural gas. The region’s overall production increased by 10% for the last 12 months (LTM) ended April 30, compared with the year-earlier period.

The Eagle Ford region is looking particularly weak, as LTM April 30 natural gas production was down 12% year-over-year, though this change partially is due to producers shifting their focus to the liquid-rich portions of the play in pursuit of better unit economics. Oil production volumes in the Eagle Ford region are roughly flat.

Industry Upset by Proposed PA Gas Production Tax 

A coalition of industrial groups has called on Pennsylvania legislators to oppose a package of energy tax increases that cleared the state Senate last month, saying it would hurt the state’s economy and smother its budding petrochemical industry. The bill is unpopular with environmentalists, too, because it would roll back some of the state’s environmental regulations. Some nonprofit groups have discussed suing to block portions of it.

The business groups have consistently opposed Democratic Gov. Tom Wolf’s tax proposals, but they’re sounding a more urgent alarm this year. A bipartisan compromise in the state Senate would impose a direct state tax on gas production for the first time. Most oil- and gas-producing states impose a production tax. The budget bill would impose a variable tax, in addition to the annual impact fee that producers pay for each well. An analysis by nonprofit group Resources for the Future estimated the production tax would have brought in $90 million in 2015. The state budget is about $32 billion.

A new tax would not only harm producers, it would raise costs for plastic manufacturers, factories and other big energy users, said Dave Taylor, president of the Pennsylvania Manufacturers’ Association. Environmentalists, too, are trying to kill the bill, which includes a series of measures aimed at speeding up permitting for gas production and would create a committee to review the state Department of Environmental Protection’s proposed regulations aimed at controlling methane emissions from the industry.

Pipeline Safety Market to Show Major Growth to 2021

The pipeline safety market size is estimated to grow from $5.57 billion in 2016 to $8.67 billion by 2021, at a Compound Annual Growth Rate (CAGR) of 9.3%. The growth is attributed to the increasing pipeline infrastructure all around the globe and increasing cyberattacks on critical infrastructure, states a new report from Research & Markets.

The growing number of pipeline projects in the Asia-Pacific (APAC) owing to the increasing energy needs are driving the growth of the market in the region; high technological spending in North America and Europe are also contributing to the growth of the pipeline safety market in these regions. However, lack of apprehension about security implementation by operators is restraining the pipeline safety growth.

The supervisory control and data acquisition (SCADA) for the pipeline segment is expected to grow at the highest CAGR among all the technologies and solutions in the forecast period as it provides a real-time solution specific to the requirements of oil and gas industry. The flexible solution is gaining traction, as it provides open interface for customization depending upon pipeline requirements.

Russia-to-Japan Gas Pipeline an ‘Ultra High-Risk’ Project

An article in the Nikkei Asian Review on Aug. 3 reported that a proposed gas pipeline linking Japan and Russia remains on hold, even though it was discussed at a meeting between Japanese Prime Minister Shinzo Abe and Russian President Vladimir Putin in April. The governments are aware of the economic difficulties facing the project but have kept the idea alive to show that, at least superficially, they are trying to strengthen bilateral economic ties.

A joint study by a group of Japanese lawmakers in the ruling party, along with Japan Oil, Gas and Metals National Corp. and a Russian energy company, envisions building a 900-mile pipeline to transport gas from the southern tip of Sakhalin – a Russian island rich in gas resources – to Japan’s Kanto region via Hokkaido, Japan’s main island in the north, and the Tohoku region. The project is estimated at $6 billion.

Gas-fired power plants produce more than 40% of Japan’s total electricity, and the country relies entirely on costly maritime deliveries of LNG. Since gas can move by pipeline without the added expenses of liquefaction and regasification, power-generation costs could drop by 30-40%. But Japanese and Russian energy experts have long regarded the pipeline as unrealistic. In recent years, however, Russia has confided with Japan its readiness to hold talks on the project.

Still, hurdles remain. The two countries have yet to pick a gas field to tap. Sakhalin fields have been reserved for Asia, and a Russian expert said there is no surplus gas for the pipeline. Meanwhile, Japanese experts warn the pipeline and gas supply network may cost much more than estimated. Energy companies in Hokkaido have already spent huge amounts on LNG import terminals, and few would welcome the pipeline. A Japanese trading firm executive said the pipeline is an “ultra-high risk” project.

Alaska Advises FERC Answers Won’t Be Ready Until January

The Alaska Gasline Development Corp. has started responding to federal regulators’ July 5 data requests for preparation of the project’s environmental impact statement, reporting that it will submit most of the requested information September through December this year – though some data will not be available until January.

The January responses will include more information about geologic hazards along the 807-mile pipeline route from Prudhoe Bay to Nikiski; separate, detailed timelines for construction and restoration work in each of six pipeline construction spreads along the mainline and the 63-mile Point Thomson pipeline; and a response to assertions made by the city of Valdez and Alaska Gasline Port Authority that Valdez would be a better site for the project’s gas liquefaction plant and marine terminal than Nikiski.

The Federal Energy Regulatory Commission (FERC) will not set a timeline for the Alaska LNG project’s environmental impact statement (EIS) until it is confident it has sufficient information to predict its work schedule and that of other federal agencies involved in the review process.

Shell-led LNG Canada Could Make Decision in 2018 

LNG Canada, a joint-venture led by Shell, is aiming for an investment decision next year on building a liquefied natural (LNG) gas export terminal on the British Columbia coast, its chief executive said Aug. 3. Andy Calitz said work on the up to $US32 billion project is “extremely active” and has not been slowed by Malaysian oil and gas company Petronas’ decision to scrap its own LNG project in the Western Canadian province, nor by a recent change in provincial government.

Shell CEO Ben van Beurden said the project partners could look at an investment decision in the “next 18 months or so.” The timing is ultimately up to the partners. Shell has a 50% stake, PetroChina owns 20%, and Japan’s Mitsubishi Corp. and Korea Gas each hold 15%.

Last year, the group delayed a final decision to find ways to reduce costs at a time when prices for LNG were hit by a global glut. They gave no new timeline for a decision on the project in Kitimat, B.C. LNG Canada also is keeping a close eye on a proposed increase in the province’s carbon tax, which will add costs to the project.

Sempra Expects Delay for First LNG from Louisiana Plant

Sempra Energy is making big investments in the burgeoning liquefied natural gas (LNG) market but during an Aug. 4 call with analysts to discuss the company’s second-quarter earnings, executives announced that Sempra’s massive LNG export project in Louisiana is running behind schedule.

It marks the second time in the past nine months that news of delays have come out regarding construction of the Cameron LNG facility in Hackberry, LA, the San Diego Union reported.

Train 1 of the Cameron facility was originally scheduled to go online in 2018, with Trains 2 and 3 following in close order. But after talking to the project’s contractors, Sempra CEO Debra Reed said  “we think it is reasonable” to expect that Train 1 may get delayed into 2019, with Trains 2 and 3 following through later that year. CB&I and the Chiyoda Corp. are the contractors for the project. Sempra officials did not go into details about what is causing the delay.

Sempra’s president of infrastructure businesses said the company has contract provisions to shield it from financial exposure due to construction delays. The $10 billion Cameron project is a partnership of Sempra, Mitsui and Mitsubishi of Japan and France-based ENGIE. At full production, the plant will be capable of making 13.5 million tons of LNG per year.

Toshiba Sets Up LNG Subsidiary to Market LNG

Energywire reports that technology titan Toshiba is staking out a new business direction: liquefied natural gas. Still reeling from its failing Westinghouse Electric nuclear power business and the fallout from bankruptcy proceedings, Toshiba America, the U.S. subsidiary of the Japanese electronics giant, announced Aug. 3 a new energy business division to be headquartered in Houston.

The new LNG venture will be based close to the Houston offices of major Japanese buyers that have recently set up shop to do business with companies pursuing LNG export deals. Osaka Gas and Chubu Electric have established offices in Houston as a result of major LNG export projects being built along the U.S. Gulf Coast.

In the new venture, Toshiba America LNG looks to purchase gas, pay for liquefaction and then export the fuel to buyers overseas. The company said it will focus on markets in the Caribbean, Latin America and Asia. The company already has a contract to take 2.2 million tons of LNG per year for 20 years from the three-train liquefaction plant under construction in Freeport, TX. Output at Freeport LNG is scheduled to start up late 2018.

The project is one of five under-utilized U.S. LNG import terminals converted to also export the fuel. Toshiba six months ago reported it was looking to sell off its Freeport LNG commitment to avoid taking a loss on the take-or-pay contract it signed.

Mainline Midstream Buys Pipeline in Oklahoma Play

Mainline Midstream, LLC, wholly owned by Riverstone Holdings and managed by Mainline Energy Partners, LLC, has acquired over 1,000 miles of oil and gas pipeline and rights of way in the SCOOP/STACK/MERGE resource play in Oklahoma. Mainline Energy, a portfolio company of Riverstone Holdings, plans to use the right-of-way to support the development of oil and gas gathering, transport, storage, stabilization and processing facilities in the prolific SCOOP/STACK/MERGE basin.


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