India’s imports of liquefied natural gas (LNG) continued to rise in August, logging an increase for the sixth consecutive month.

India imported 2.3 billion cubic meters of LNG or about 1.7 million tonnes last month, a rise of 9.9 percent year-on-year, according to the data from oil ministry’s Petroleum Planning and Analysis Cell (PPAC).

The costs of these imports were at $0.9 billion compared to $0.5 billion in August last year.

On the other side, India’s domestic natural gas production rose just 0.6 percent in August to 2.78 Bcm.

In the April-August period, India imported 11.75 Bcm or about 8.69 million tonnes of LNG. This represents an increase of 18.1 percent when compared to the same period last year, the PPAC data shows.

India currently imports LNG via Petronet’s Dahej and Kochi LNG terminals, Shell’s Hazira plant, and the Dabhol terminal operated by Ratnagiri Gas and Power.

https://www.lngworldnews.com/indias-monthly-lng-imports-continue-to-rise/

BP targets Texas for American comeback

At the beginning of this century, the British energy company BP achieved its own American dream, becoming the largest oil and gas producer in the United States after spending a combined $75 billion to buy the oil companies Amoco and ARCO in audacious back-to-back deals.

The future looked bright — but it didn’t last. A series of disasters that began with the 2005 Texas City refinery explosion that killed 15 and culminated in 2010 with the Deepwater Horizon disaster forced BP to sell assets and dramatically shrink its holdings as it paid tens of billions of dollars in cleanup costs, damages and penalties to settle civil and criminal cases.

Now, nearly a decade after Deepwater Horizon, BP is ready to grow again, betting much of its comeback on Texas after completing the biggest energy deal in the world this year. Its pending acquisition of the U.S. shale assets of the Australian mining company BHP Billiton for $10.5 billions puts BP in the Permian Basin in West Texas and the Eagle Ford shale in South Texas, and expands its presence in the Haynesville shale in East Texas, positioning itself to compete for the spot as the biggest producer in the United States.

If the acquisition pays off, it would likely mean additional growth in Houston, where BP’s U.S. subsidiary is headquartered and the company employs about 4,500 people. Bill Arnold, a professor of energy management at Rice University and former executive at the Anglo-Dutch oil major Royal Dutch Shell, said BP appears headed on an upward trajectory again after riding a roller coaster over the past 20 years.

“There was a real question of whether the company could even survive,” Arnold said. “But now BP is back and it’s ready for business.”

The American comeback is led by Susan Dio, who in May became the first woman to head BP’s U.S. operations. Dio, who began at BP as a chemical engineer and rose over a 35-year career to become president of BP America, will oversee and coordinate BP’s dealings from Alaska to the deepwater Gulf of Mexico. She and her colleagues view Texas as the the clearest path for BP to resume its growth in the United States and catch up with rivals such as Exxon Mobil, which invested billions to expand in the Permian Basin, the nation’s most prolific shale play.

With the BHP acquisitions, Texas is now at the center of BP’s global ambitions and Dio a key player in BP’s shift from defense to offense. The British supermajor has more oil and gas producing assets in the United States than any other country. Its Houston campus is its largest outside of London.

“We just doubled down in the U.S.,” Dio said in an interview. “We’re now forward looking.”

Targeting Texas

The BHP deal, expected to close by the end of October, represents BP’s biggest acquisition since it bought the Atlantic Richfield Co., called ARCO, in 2000 year for $27 billion. The new acquisition includes 83,000 net acres in the oil-rich Delaware Basin portion of the Permian, 236,000 acres in the Eagle Ford and 193,000 acres in the gas-heavy Haynesville in Texas and Louisiana. The assets combine to produce nearly 200,000 barrels of oil equivalent a day with the potential for much more as BP adds drilling rigs.

BP estimates its U.S. energy production, which includes a major presence in the Gulf of Mexico, will grow to 885,000 barrels of oil equivalent per day after the BHP deal closes in October. That’s competitive with the 975,000 barrels of oil equivalent a day that the top U.S. producer, Exxon Mobil, said it pumped in the United States during the second quarter.

BP’s deal with BHP is a story of both bad and oddly fortuitous timing, analysts said. BHP Billiton bought big into U.S. shale back in 2011 when oil was priced close to $100 a barrel, spending more than than $12 billion to buy Houston oil and gas company Petrohawk Energy and $5 billion for acreage from Oklahoma City’s Chesapeake Energy.

But oil prices began crashing in 2014, falling to a low of $26 a barrel in early 2016, eventually convincing BHP to pull out after taking huge financial losses. Company executives decided to stick with its more stable mining commodities such as copper, nickel and iron ore.

The Deepwater Horizon disaster, which killed 11 workers and released nearly 4 million barrels of oil into the Gulf, drove BP to sell some $75 billion of its assets. Most of those sales, however, were closed well before the collapse in oil prices that began in 2014, meaning the oil and gas holdings sold for top dollar.

That made it easier for BP to pay cleanup costs, penalties and other obligations that topped $65 billion, paving the way for BP to ride out the bust and win the bidding for BHP assets with U.S. oil prices hovering around $70 a barrel.

“BP was forced to take a hard look at its portfolio and make divestments even before oil prices fell,” said Allen Good, an energy analyst at Morningstar. “Now they’re in growth mode and adding a lot. And there’s no better place in the world to be than the Permian.”

BP won’t discuss its development plans for its new Texas holdings. But the timing again appears to be working for the company. It’s likely BP can plan its development and begin production as new pipelines come online to relieve capacity constraints that are forcing oil companies to slow production and discount prices.

While BP expects to focus on its shale holdings, it also is growing in the Gulf of Mexico again, winning 19 federal lease bids — the second most after Exxon Mobil — for $13 million last month. It has moved ahead with construction of a massive deepwater platform for its $9 billion Mad Dog Phase 2 that’s located 200 miles south of New Orleans. The first platform came online in 2005.

Home again

The progress has not come easily. In addition to the damage Deepwater Horizon did to the company’s reputation — as well as the Gulf, coastal areas and marine and wildlife — paying for the disaster led BP to sell refineries in Texas City and Carson, Calif., large holdings in the Gulf of Mexico and Alaska, and 400,000 net acres in the Permian Basin. It sold its Permian assets to Houston’s Apache Corp. for about $3 billion — just before the shale oil boom took off.

The company slashed jobs, cutting its Houston 7,500-person workforce nearly in half. Some of those jobs will return with the BHP deal, but, Dio conceded, the stigma of Deepwater Horizon and the lessons learned will resonate for years.

“We made some tough decisions on assets,” Dio said. “We’ve spent the last eight years redefining ourselves, and we transformed the company. We’ve reset the culture and empowered the employees to stop work if anything is unsafe.”

Dio, who joins BP’s 13-person global executive team that makes corporate decisions, gives U.S. operations a stronger seat at the table that didn’t exist under previous BP America presidents. Dio will join CEO Robert Dudley in infusing more of an American, entrepreneurial attitude into the leadership of company. Dudley, who stepped into the Deepwater Horizon crisis after the board forced out Tony Hayward, is a Mississippi native who earned his master’s degree in business administration from Southern Methodist University in Dallas.

Dio is a self-described southern military brat who lived in seven cities in seven states before attending and graduating from the University of Mississippi. She’s worked about 25 years of her 35 years at BP along the Texas Gulf Coast as a chemical engineer and then as a manager of refining and chemical operations. She most recently worked in London for three years as the CEO of BP Shipping, which oversees BP’s fleet of more than 70 vessels carrying oil, gas, fuel and chemicals, before moving back to Houston this year.

“Texas is home,” Dio said. “I’m thrilled to be back here. I do love London, but it’s not home.”

BP just opened a new Denver office, which will oversee its shale operations. BP has honed its shale skills in plays in Colorado, Oklahoma and East Texas. Now, with the BHP acquisition, BP is ready to compete, Dio said.

“We’re not coming in blind,” she said. “We’re looking to apply what we’ve learned to a much larger set of assets.”

https://www.energyvoice.com/oilandgas/americas/182129/bp-targets-texas-for-american-comeback/

Brazilian oil industry regulator ANP on Thursday approved an additional payment of 706 million reais ($173.19 million) to state-controlled oil company Petróleo Brasileiro SA to compensate for diesel subsidies, according to a statement.

Visitors walk during a visit to Brazil's Petrobras P-66 oil rig in the offshore Santos basin in Rio de Janeiro, Brazil September 5, 2018. Picture taken September 5. REUTERS/Pilar Olivares

Earlier this week, ANP said it green-lighted a payment of 877 million reais to Petrobras, the first for the company since the subsidy program was unveiled in late May to end a truckers’ strike over high diesel prices.

The announcement from ANP confirmed a Reuters report earlier on Thursday.

The subsidy plan raised fears of further state meddling in Petrobras, the world’s most indebted oil company, and has spurred criticism of the government’s subsidy program and lack of timely payment of compensation.

https://www.reuters.com/article/us-petrobras-subsidies/brazil-oks-second-diesel-subsidy-payment-of-173-million-to-petrobras-idUSKCN1M02XS

Royal Dutch Shell Plc, is in talks to sell its interest in a Gulf of Mexico oilfield to Focus Oil, according to people familiar with the matter.

The deal could value Shell’s stake in the Caesar Tonga field at about $1.3 billion, said the people, who asked to not be identified because the matter isn’t public. A deal hasn’t been completed and negotiations could still fall apart, they said.

Shell has a 22.5 percent working interest in Caesar Tonga, with the rest owned by companies including field operator Anadarko Petroleum Corp., Equinor ASA and Chevron Corp., according to company filings.

A sale could further Shell’s efforts to dispose of mature assets to free up cash for shareholder returns and to improve growth prospects, as well as help pay down debt after it spent more than $50 billion buying BG Group in 2016. Shell said it would divest $30 billion in assets to pay for that deal. When it released its second-quarter results in July, it said it was about $2.5 billion away from achieving that goal.

Shell declined to comment. Houston-based Focus Oil and Anadarko didn’t immediately respond to requests for comment.

Caesar Tonga consists of three separate discoveries in the southern Green Canyon portion of the gulf that were made from 2003 to 2007, according to information from energy consultant Wood Mackenzie Ltd. Production began in 2012, with Anadarko estimating at the time that the field held as much as 400 million barrels of oil equivalent in resources.

Focus Oil was founded in 2015 and is led by Chief Executive Officer Brady Rodgers, who previously worked as an engineer and energy banker. The company focuses on deep-water resources and targets “the top 50 oil fields for acquisition, the crown jewels of major oil company portfolios,” according to its website .

https://finance.yahoo.com/news/shell-talks-sell-1-3-203826518.html

Mexico should speed up development of its natural gas reserves, including potentially massive shale deposits, to curb a growing “supply risk” fed by excessive dependence on U.S. supplies, the industry regulator proposed on Thursday.

While the country has long been a major oil and gas producer, an extended output slump forced Mexico last year to turn to foreign supplies for 84 percent of its total natural gas demand, almost all of which came from the United States.

The commodity is increasingly used to fuel the country’s growing manufacturing sector as well as its electricity needs.

“We need to diversify (sources of natural gas) because we are very concentrated,” said Juan Carlos Zepeda, president of the National Hydrocarbons Commission (CNH), Mexico’s oil and gas regulator, in an interview before announcing the proposals.

He pointed to shale gas resources estimated at more than 141 trillion cubic feet that should be developed.

“The priority of our national security related to natural gas does not allow the luxury of turning our back on this potential,” he said.

Mexico’s incoming president, however, has said he will not permit hydraulic fracking, the widely used technique to unlock oil and gas from dense shale rock that critics say harms underground water supplies.

“We will no longer use that method to extract petroleum,” President-elect Andres Manuel Lopez Obrador told reporters just weeks after winning a landslide election victory on July 1.

Set to become Mexico’s first leftist leader in decades in December, Lopez Obrador has said he will focus on strengthening state-owned Petróleos Mexicanos [PEMX.UL], known as Pemex.

So far this year, Pemex has produced an average of 4.83 billion cubic feet per day (bcf/d) of natural gas, down by nearly a third compared to peak production of 7.03 bcf/d in 2009.

“We’ll have to be convincing,” CNH Commissioner Hector Moreira said in an interview, noting that two-thirds of Mexico’s estimated natural gas supplies are in so-called non-conventional shale deposits.

He added that three main gas pipelines on the U.S.-Mexico border make imports vulnerable to disruption.

Both Zepeda and Moreira propose that oil and gas auctions continue under the incoming government, especially in gas-rich areas, and that new fiscal incentives be enacted that allow producers to immediately deduct drilling costs with no required royalty payments.

They also pitch a new state-owned company focused exclusively on producing natural gas, similar to Russia’s Gazprom.

https://www.reuters.com/article/us-mexico-gas/mexico-should-tap-natural-gas-to-offset-u-s-supply-risk-regulator-idUSKCN1M03CA

Shivering villagers in northern China resorted to burning corn cobs and wood scraps last winter because a poorly executed coal-to-natural gas conversion left thousands of them without a reliable source of fuel to heat their homes.

Now, as winter again approaches, the country’s largest gas players – like distributor China Gas Holdings – are under intense pressure to ensure demand will be met, as the central government presses on with its programme – kicked off last year – to combat choking smog by converting roughly 20 million rural households in northern regions to the cleaner source of energy by 2020.

“The gas shortage will not be as bad as last year, and the reported cases of freezing villagers will definitely not happen again this year,” Kevin Zhu Weiwei, executive director and managing vice-president of China Gas, confidently told a small group of reporters invited to the eastern coastal city Qingdao to see its operations and meet with a few villagers.

Whether distributors like China Gas as well as gas producers succeed this winter is of high-stakes importance to President Xi Jinping, who has made the “war on pollution” a top priority in recent years, even engraving the Chinese word meaning beautiful – mei li – into the country’s constitution in March. He will not want to see a repeat of buddled-up schoolchildren shivering outdoors, trying to get warmed by the sun.

Stephen Chazen, the former chief executive of Occidental Petroleum Corp. who earlier this year purchased the Eagle Ford Shale assets of Houston-based EnerVest for $2.7 billion, said he expects to put 40 percent of Magnolia's cash flow toward small acquisitions.

Chazen, who made the EnerVest deal with investment firm TPG Pace Energy, made the comments Thursday morning at the DUG Eagle Ford conference held by Hart Energy in San Antonio.

He called the acquisitions that Magnolia is eyeing as "small deals" of acreage around the land the company already holds.

The other 60 percent of cash flow will be spent on drilling and operations.

When asked how he looks to grow the company, Chazen said he hopes the company will grow from a $3.5 billion market capitalization today to $10 billion in 5 years.

His strategy: wring out every barrel of oil from his acreage.

"I'm not trying to accelerate production, I'm trying to extract every barrel economically," Chazen said.

The company bought 360,000 acres from Enervest in March. In August Magnolia announced a $191 million deal to acquire 114,000 acres in South Texas' Giddings Field from Harvest Oil & Gas Corp.

https://www.chron.com/business/energy/article/Stephen-Chazen-Magnolia-aims-to-be-10-company-13244164.php

China may issue an additional 3 million to 4 million tonnes of permits for refined fuel exports for 2018 to prevent state-owned refiners from having to slash throughput rates, according to three sources briefed on the matter.

The government has been looking to keep fuel export quotas at around 43 million tonnes this year, steady with 2017 levels, to maintain overall trade balances.

But the state refiners have been using the quotas already granted for this year faster than expected, rushing to ship more gasoline, diesel and jet kerosene overseas in the first nine months compared to the same period of 2017 because domestic refinery production has expanded faster than demand.

While exports may not be as lucrative as sales in the domestic market, where margins are largely guaranteed, the overseas shipments helped bolster margins at home by thinning local fuel supplies.

Refiners - including Sinopec Corp, PetroChina, CNOOC [SASACY.UL] and Sinochem [SASADA.UL] - will have already used about 35 million tonnes, or 81 percent of the total grants so far by end-September, according to a state oil executive with direct knowledge of the situation.

“The big oil firms are trying this week to persuade the government to release more quotas, or they may be forced to cut runs in the fourth quarter as the remainder is far from enough,” said the executive.

Most refiners would try to avoid reducing runs in the fourth quarter, when diesel fuel demand typically picks up with an increase in construction activities and the lifting of a summer fishing ban, and the Golden Week holiday of early October, which lifts gasoline and jet fuel consumption.

The three sources at state oil firms estimated the government could issue an additional 3 million to 4 million tonnes of fuel export quotas as early as next week.

The sources declined to be named as the discussions are not public. Representatives of CNPC, Sinopec, CNOOC and Sinochem did not respond to requests for comment.

The National Development & Reform Commission (NDRC) and Ministry of Commerce also did not respond to queries.

Chinese customs data showed huge gains in transportation fuel exports this year. Gasoline exports in the first seven months grew 44 percent over the same period last year to 8.33 million tonnes, diesel rose 25 percent to 11.68 million tonnes, and jet kerosene gained 15 percent to 8.08 million tonnes.

State-run refiners earned bumper profits this year as diesel demand firmed while many small fuel blenders were forced out of business and some independent oil processors slashed output over the summer months because of stricter government tax scrutiny enacted from March.

https://www.reuters.com/article/us-china-oil-export-quotas/china-may-issue-more-fuel-export-quotas-to-refiners-to-prevent-run-cuts-sources-idUSKCN1M111A

French oil major Total said today that its Glendronach prospect could contain one trillion cubic feet (tcf) of gas.

The Stena Don semi-submersible rig started drilling the well in May, encountering a 140 ft gas column.

Initial tests showed good reservoir quality and well production deliverability, Total said.

Arnaud Breuillac, president of exploration and production at Total, said: “Glendronach is a significant discovery for Total which gives us access to additional gas resources in one of our core areas and validates our exploration strategy.

“Located on an emerging play of the prolific West of Shetland area, the discovery can be commercialized quickly and at low cost by leveraging the existing Laggan-Tormore infrastructure.”

Total has a 60% operated interest in Glendronach, while partners Ineos and SSE each have 20%.

https://www.energyvoice.com/oilandgas/north-sea/182216/total-reveals-major-gas-find-west-of-shetland/

Fieldwood Energy, an offshore oil and gas explorer that emerged from bankruptcy in April, is weighing an initial public offering, according to people familiar with the matter.

The Houston, Texas-based company is exploring filing a public offering in early 2019 that could value the company at more than $5 billion, said one the people, who asked to not be identified because the matter isn’t public.

Fieldwood is one of the largest oil producers in the Gulf of Mexico. It filed for Chapter 11 bankruptcy protection in February after incurring too much debt in a $5-billion acquisition spree before oil prices crashed in 2014. It exited bankruptcy two months later after reaching an unusual restructuring agreement with a creditor group that included Riverstone Holdings LLC, its owner before it went to court.

The energy-focused buyout firm remains a large shareholder in Fieldwood after swapping some of its debt for new equity, according to court documents. Riverstone and other creditors also got the right to purchase shares in the post-bankrupt Fieldwood to help fund its purchase of Noble Energy Inc.’s Gulf of Mexico business, which closed in April.

Fieldwood is the largest oil and gas explorer in a shallow part of the Gulf known as the shelf, where it has more than 500 drilling platforms across 2 million gross acres, according to its website.

It was founded in 2012, when it secured a $600-million investment commitment from Riverstone. Over the next two years, it bought operations in the gulf from Apache Corp. and SandRidge Energy Inc.

https://www.worldoil.com/news/2018/9/23/major-gulf-of-mexico-producer-weighs-2019-ipo

For the first time in five years, takeaway expansions are outpacing Northeast production growth. Major natural gas takeaway capacity additions on large-diameter pipes like Tallgrass Energy’s Rockies Express Pipeline and Energy Transfer Partners’ Rover Pipeline over the past couple of years are allowing Marcellus/Utica natural gas producers to send record amounts of gas supply to the Midwest and, indirectly, to the Gulf Coast region. At the same time, there are some small pockets of unused takeaway capacity appearing on some of the legacy routes out of the region, which means that Appalachian basis levels — prices relative to Henry Hub — have risen to the strongest levels since 2013. For downstream markets like Chicago and Dawn, ON, that’s meant a flood of gas and lower prices. In today’s blog, we continue our series on the Northeast gas market with the effects of these new dynamics on gas price relationships.

This our series looking at recent shifts in U.S. Northeast natural gas flow and pricing dynamics. As we said in Part 1, Northeast gas production weighs heavily into the U.S. supply-demand balance, with nearly half of the 8 Bcf/d of total Lower-48 gas production growth this year to date coming from the Marcellus/Utica producing regions. Marcellus/Utica volumes are soaring above 29 Bcf/d currently, up from 16 Bcf/d five years ago. Since the Northeast flipped from a net demand to net supply region in 2015, the bulk of this supply growth has been squeezing out from the Northeast, facilitated by numerous pipeline capacity expansions and pushing into the Midwest and Gulf Coast destination markets for which other supply regions are also competing.

As much as Marcellus/Utica production has grown, producers until now have been constrained by takeaway capacity from the region and plagued by heavily discounted supply prices (see Living in Fast Forward Curves). However, as we discussed in Part 2, producers’ supply prices this year have improved dramatically, with the Dominion South price in Appalachia averaging $0.40/MMBtu below Henry Hub this July and August, compared with well over $1/MMBtu behind Henry in the past four years.

EAsing capacity constraints, particularly as Energy Transfer’s new Ohio-to-Midwest route — Rover Pipeline — has ramped up. Rover began partial service in September 2017 with 700 MMcf/d but flows have since climbed to nearly 3 Bcf/d now, with the completion of additional mainline and supply laterals. While some of these incremental flows have come from new production, a good portion also has been redirected from other outbound pipes, effectively leaving pockets of capacity open on those other routes. As we detailed in Part 3, gas flows on Tallgrass Energy’s Rockies Express Pipeline (REX) as well as several legacy systems — Columbia Gas Transmission (CGT), Tennessee Gas Pipeline (TGP) and Dominion Energy Transmission — have gone from running at capacity in recent years to flowing below capacity this year, even as production has surged higher.

With the shift of gas flows to the new westbound capacity on Rover, more and more Marcellus/Utica gas is ending up in the Midwest. So, as Dominion South basis (purple star in Figure 1 below) improves, there’s been an opposite effect on prices at Midwest destination markets such as Chicago Citygate (red star), MichCon Citygate (green star) and Dawn (Ontario; blue star).

Figure 1. Appalachia and Midwest Pricing Hubs. Source: RBN Energy

You’ll recall from our previous blogs on Rover — see Are You Ready Part 2 — the 711-mile greenfield takeaway project involves moving Marcellus/Utica gas northwest across Ohio to Defiance County, where the gas is then delivered into one of three interconnecting pipes that serve the Chicago/Midwest markets:  Energy Transfer’s Panhandle Eastern Pipeline, which extends from the Texas Panhandle northeast to Michigan; TransCanada’s ANR Pipeline, which serves the Chicago area as well as western and southern parts of Michigan; and a market segment that interconnects with Vector Pipeline, which moves gas directly from the Chicago area to the MichCon and Dawn markets and also interconnects with ANR. (Rover has a precedent agreement in place with Vector Pipeline and its Canadian affiliate for up to 950 MMcf/d of firm transportation capacity north into the Michigan and Dawn market areas, in addition to its contracted capacity to go north and south on Panhandle.)

Of the average 2.2 Bcf/d of gas that Rover has moved into the Midwest in 2018 to date, we estimate that about half has targeted the Gulf Coast destinations, either physically or by displacement, while the other half has ended up in the Midwest market. There is about 300 MMcf/d or so being pushed back to Chicago on other interconnects off Rover, while 800 MMcf/d has moved to Dawn via the Vector capacity. That has effectively displaced 500 MMcf/d or so of Dawn’s supply to MichCon, where the bulk of it seems to have gone into storage, save for a small portion — about 100 MMcf/d — that’s also been displaced all the way back to Chicago. It’s worth noting here that as Rockies producers are losing West Coast market share to Canada, REX also is sending more gas to Chicago, much of which is surplus that’s ending up in storage.

All this even as Rover has been operating at a partial capacity of 2 Bcf/d for much of this year (from late January 2018 until June 2018). Capacity on the line surpassed the 2.5 Bcf/d mark only in the past few weeks, and there’s another 0.5 Bcf/d of capacity still outstanding as the operators await approval of its final two supply laterals. But already the basis impacts on the downstream markets are evident.

Here’s another look at Dominion South basis in Figure 1 below, which plots monthly average levels for 2015 (blue line), 2016 (red line), 2017 (green line) and 2018 (purple line), based on pricing data from Natural Gas Intelligence (NGI).

Figure 2. Dominion South Basis. Source: NGI

You can see the recent strength in the purple line, with Dominion South basis this year to date averaging at minus-$0.46/MMBtu, compared with minus-$0.84 in 2017 and minus-$1.00 or more in the two years before that. Basis has diverged sharply upward over the past few months in particular, at a time when it has typically weakened in previous years.

In contrast, Midwest basis has been trending weaker on average, compared with prior years. MichCon basis (left graph in Figure 3 below) flipped from a plus-$0.22 in 2015 to a minus-$0.04 in 2017 and that’s dropped further to minus-$0.15 this year to date. Dawn basis in 2018 — as shown in the right graph in Figure 3 — has averaged nearly flat to Henry at plus-$0.01/MMBtu, after averaging plus-$0.07 in 2017 and plus-$0.35 in 2015.

Figure 3. MichCon and Dawn Basis. Source: NGI

Changes in Chicago basis (Figure 4 below) have been more modest so far this year to date, with cash prices weakening by just $0.02 relative to Henry Hub to a basis of minus-$0.10, from minus-$0.07 in 2017. Still, as more westbound capacity is due on Rover –– and with Enbridge’s 1.5-Bcf/d NEXUS Gas Transmission project also on the way –– all these markets will face further downward pressure in the coming months, and particularly by next summer after peak winter demand dissipates. (NEXUS last week filed an in-service request for portions of its mainline facilities, including its new 258-mile, 36-inch-diameter mainline, the Hanoverton compressor station in Columbiana County, OH, and metering and regulating facilities at interconnects with the Kensington processing plant in Hanover Township, OH; the DTE Gas Co. in Ypsilanti Township, OH; Texas Eastern Transmission in Hanover and Columbia Gas of Ohio in Sandusky County, OH. These facilities would open nearly 1 Bcf/d of capacity on the line as early as September 28, 2018.)

Figure 4. Chicago Citygate Basis. Source: NGI

If we look at the current forward curve for Dominion South, for instance, it’s currently trading about minus-$0.45/MMBtu on average for 2019, more or less flat to the 2018-to-date average. However, the market has priced MichCon forward basis for next year to weaken further — to about minus-$0.23, compared with the minus-$0.15 average this year to date.

These recent developments are a taste of what’s to come. Besides Rover and NEXUS, there are other expansions on the way, with many targeting the Gulf Coast. Takeaway capacity constraints will continue easing and whittle away at the supply area price discounts, presumably dismantling major barriers that have been holding producers back. What does that bode for overall U.S. production growth?

In the next episode, we’ll wrap up this series with a look at the RBN outlook and implications of the coming Northeast and U.S. natural gas production growth.

https://rbnenergy.com/dog-days-are-over-part4-northeast-gas-takeaway-expansions-reshape-regional-price-relationships

China, the world’s second-largest importer of liquefied natural gas (LNG), boosted its imports of the chilled fuel by 51.5 percent in August, according to the General Administration of Customs data.

The world’s largest energy consumer imported 4.71 million tonnes of LNG last month, compared to 3.14 million tonnes in August 2017, the data shows.

Compared to the previous month, imports of the fuel rose 13.5 percent.

China’s LNG imports have been steadily growing this year as the country is replacing coal-powered generation with natural gas in its strategy for cleaner air.

In the January-August period, China took 32.63 million tonnes of LNG, up 47.8 percent year-on-year, the customs data said.

https://www.lngworldnews.com/chinese-aug-lng-imports-surge/

Hydraulic fracturing crews work on completing wells in the Haynesville shale in East Texas. The wells are operated by XTO Energy, a subsidiary of Exxon Mobil.

A newly expanded climate initiative of the largest energy companies worldwide pledged Monday to reduce its methane emissions by more than 20 percent by 2025.

The announcement comes days after U.S. companies Exxon Mobil, Chevron and Occidental Petroleum joined the Oil and Gas Climate Initiative that was launched four years ago by the biggest European energy firms. At the time, the American companies refused to sign on.

The expanded 13-company initiative said Monday it would cut its emissions of methane - the primary component of natural gas - from 0.32 percent in 2017 to at least 0.25 percent by 2025 with a goal of achieving 0.20 percent.

Several energy supermajors in recent years have begun a pivot away from crude oil and toward more cleaner-burning natural gas.

Natural gas produces far less carbon dioxide than coal and oil and is considered a bridge fuel that the world can rely on until renewable energy sources like wind and solar power become more widespread and affordable. But methane emissions — from gas wells to pipeline leaks — have long been considered the Achilles' heel of natural gas. Methane has 80 times the global warming effects of carbon dioxide, although its impacts don't last as long in the atmosphere.

"Our aim is to work towards near-zero methane emissions from the full gas value chain in support of achieving the goals of the Paris Agreement," the 13 companies stated. "We have worked to make our ambition concrete, ac­tionable and measurable, helping to ensure that natural gas can realize its full potential in a low-emis­sions future."

Achieving the 0.25 percent goal would reduce global methane emissions by 350,000 metric tons a year.

The initiative pledges to support the recent Paris climate accord and with an aim toward eliminating all routine methane flaring by 2030.

Just last week, Royal Dutch Shell, one of the founding members of the initiative, said it would achieve the more ambitious 0.20 percent emissions goal by 2025.

The news comes after a study this summer found that annual methane emission rates from energy companies are about 60 percent more than what the U.S. Environmental Protection Agency reports.

The oil and gas sector is the largest source of U.S. methane emissions, according to the Energy Department. Surging gas production from shale drilling and hydraulic fracturing, called fracking, has increased methane emissions through much of the past 10 to 15 years.

Apart from Shell, Exxon Mobil, Chevron and Occidental, the other member companies are the United Kingdom's BP, Norway's Equinor, Italy's Eni, France's Total, Spain's Repsol, China's CNPC, Brazil's Petrobras, Mexico's Pemex and Saudi Arabia's Saudi Aramco.

https://www.chron.com/business/energy/article/Biggest-energy-companies-pledge-20-percent-13252920.php

Exxon Mobil Corp , Royal Dutch Shell Plc and other companies will gather on Friday in possibly their last crack at Brazil’s coveted offshore oil for another four years, as a wide-open election spurs fears about barriers to foreign investment.

The auction in Rio de Janeiro for four blocks in the Santos and Campos basins comes just a week before the most unpredictable presidential election in a generation, which features candidates that may seek to slow the pace of oil auctions, revise market-friendly legislation or even claw back oil areas already handed out.

“They can try to revise the whole process of opening up (the oil industry) to international oil companies,” said an oil services industry executive, who declined to be named.

Lured by world class geology, shrinking reserves elsewhere, and rising oil prices, companies have dropped big money on Brazil, Latin America’s top oil producer, to lock in stakes to its pre-salt layer, where billions of barrels of oil are trapped under a thick layer of salt offshore.

China’s CNOOC, Chevron Corp, BP, Norway’s Equinor, and France’s Total are also all registered to participate in the auction.

Their interest has been fanned by industry-friendly policies under center-right President Michel Temer, including a loosening of rules that had favored local suppliers, an extension of tax sweeteners, and the removal of a requirement that state oil giant Petrobras be sole operator in pre-salt blocks.

Fears of a rollback of such policies should encourage big bets on Friday, according to Edmar Almeida, an energy professor at the Federal University of Rio de Janeiro.

“It will be a hotly contested auction,” he said.

Presidential right-wing frontrunner Jair Bolsonaro has said little about the oil sector, although as a congressman he once voted against easing Petrobras’ oil monopoly. He has floated the idea of privatizing Petrobras and has indicated that he will champion a market-friendly approach if he wins.

However, opinion polls indicate that a likely run-off vote on Oct. 28 would be a close contest. Fernando Haddad, a leftist academic who has climbed into the No. 2 spot after an endorsement from jailed former president Luiz Inacio Lula da Silva, has a much more nationalistic view of the industry.

Vowing to “recover the pre-salt to serve the future of the Brazilian people, not the interests of international companies,” according to his platform, he would restore stricter requirements for using local suppliers.

It is unclear if Haddad would also adopt Lula’s pledge to revert to giving Petrobras the sole right to operate pre-salt fields and slow the pace of pre-salt auctions.

Ciro Gomes, a leftist former state governor in third place, has threatened to freeze auctions and expropriate blocks already handed out.

If Haddad or Gomes win, “we can say goodbye to auctions,” said another oil industry executive, who asked not be named. “They want to renationalize everything. It will be hell,” he said.

The fiercest bids this week are expected to be for the Tita and Saturno blocks in the Santos basin, which were withdrawn by a court from a prior auction in March, disappointing Exxon.

Both Pau Brasil in the Santos basin, and the Southwest of Tartaruga Verde in the Campos basin received no bids in an auction last year. But this time, Petrobras exercised its right of first refusal to bid for the Tartaruga Verde block, adjacent to an area it already owns.

Under Brazilian rules, Petrobras can express advance interest in operating a block where it would control at least a 30 percent stake, though it can still bid on other blocks on the day of the auction.

Companies will compete by pledging the greatest share of oil - subtracting overhead costs - to the government, with minimums ranging from 9.5 percent to 35 percent.

https://uk.reuters.com/article/brazil-oil/preview-big-oil-readies-brazil-offshore-bets-fearing-election-result-idUKL2N1W61RT

Halliburton Company has released the iCruise Intelligent Rotary Steerable System (RSS), a breakthrough technology that delivers faster drilling, accurate steering and longer laterals.

Today, operators need to efficiently and reliably drill longer laterals faster, which requires a drilling system that can steer accurately through high-angle wellbores in one run and achieve target depth on time and on budget. The iCruise system provides the highest mechanical specifications available with 400 RPM and up to 18 degrees/100 ft dogleg capabilities to drill fast and with greater accuracy.

The iCruise modular design can be configured to drill a long lateral or to increase accuracy in formations where well trajectory changes rapidly. Steerability and cutting efficiency can be further improved by matching the new Halliburton GeoTech (GTi) drill bit with the iCruise system.

"Halliburton has engineered a rotary steerable system that incorporates advanced sensors and electronics, sophisticated algorithms and high-speed processors to help operators place wells more accurately, reduce well time and maximize asset value,” said Lamar Duhon, V.P. of Sperry Drilling. “The system can also guide decisions around drilling parameters, vibration mitigation and maintenance to improve reliability."

Operators have deployed the iCruise system in multiple basins around the world including in North America and the Middle East. In North America, iCruise helped an operator drill more than one mile in a complex reservoir while geosteering through a 30-ft productive zone. The system maintained the wellbore 100% in the reservoir reducing time and maximizing recovery.

https://www.worldoil.com/news/2018/9/24/halliburton-releases-intelligent-rotary-steerable-system

Capacity down to 2.5 Bcf/d this winter

Average winter demand on system is 2.86 Bcf/d

The Southern California Gas Company's system has been heavily restricted all summer and continues to cause price volatility in Southern California. The volatility is likely to continue this winter if capacity restrictions continue along with the lower-than-normal levels of gas in storage in the region, according to S&P Global Platts Analytics.

Recent notifications have impacted both the short-term and longer-term dynamics of the system. Not only has SoCal Gas announced the Aliso Canyon storage facility will limit injections this week due to full inventories, but it has also implemented further Southern Zone restrictions that will limit flows through the zone by an additional 156 MMcf/d. In early July, the California Public Utilities Commission allowed SoCal Gas to increase the Aliso Canyon storage field's working gas capacity by 10 Bcf, bringing the facility's total capacity to 34 Bcf. Platts Analytics expects SoCal Gas in storage will enter the winter season close to its total capacity of 84 Bcf.

Prior to the leak at the facility from October 2015 to February 2016, the Aliso Canyon field by itself had a working gas capacity of 86 Bcf and was the largest storage facility in the US Energy Information Administration's Pacific region.

RESTRICTIONS

This winter, storage inventories will be roughly 17 Bcf more than the start of last winter. Despite levels being slightly higher year over year, current pipeline receipt capacity is about 600 MMcf/d below what it was entering last winter. This will cause SoCal Gas -- if no changes occur to the current restrictions -- to rely much more heavily on storage withdrawals through the winter in order to meet on-system demand, which has averaged 2.8 Bcf/d over the last five years.

SoCal Gas' restriction on the Southern Zone line 2001, which will cut capacity in the zone by an additional 156 MMcf/d, is slated to end on October 3. Total Southern Zone capacity was previously limited to 729 MMcf/d and the additional restriction reduces total capacity to 572 MMcf/d. SoCal Gas cited "necessary remediation due to safety related conditions" for the restriction.

Current flows through the Southern Zone have averaged 760 MMcf/d this September prior to the restriction. With the additional capacity cut it can be expected for receipts from Ehrenberg to decline to meet the new capacity limit. SoCal City-Gate next-day basis increased 55 cents following the news of the restrictions last Wednesday. Volatile prices can be expected to continue through October 3, especially if on-system demand reaches more than 2.3 Bcf/d, which is the current pipeline receipt capacity on the SoCal Gas system.

VOLATILITY LIKELY

The restrictions currently on the SoCal Gas system will limit pipeline receipt capacity to approximately 2.5 Bcf/d after October 3. The main long-term maintenances currently causing these restrictions have an end date of "to be determined," according to SoCal Gas' most recent maintenance posting. With no end date listed -- and assuming the maintenances continue through the winter -- prices at SoCal City-Gate may react similarly or even more severely than this past summer as on-system demand in the winter is typically higher than during summer. This past summer, which included the same restrictions, saw prices reach record highs at SoCal City-Gate when a period of sustained higher demand occurred. The five-year average for on-system demand on SoCal Gas' system during the winter is 2.86 Bcf/d, which would result in about 350 MMcf/d of storage withdrawal if pipeline receipt capacity remained at 2.5 Bcf/d.

As the system will already be relying on storage withdrawals to meet even average winter demand loads, any spike in demand will most likely cause prices to react in a similar manner as this past summer. On July 25, basis at SoCal City-Gate reached an all-time high of $36.61/MMBtu as on-system demand was 2.9 Bcf/d, which is just slightly higher than average winter demand on the system.

https://www.spglobal.com/platts/en/market-insights/latest-news/natural-gas/092418-analysis-socal-gas-system-restrictions-could-lead-to-winter-price-spikes

Swedish oil firm Lundin Petroleum expects to increase its resource estimate for the Alta discovery in Norway’s Arctic region following a successful two-month production test.

Finding significant oil reserves in the Norwegian Arctic has been challenging for oil firms, but Alta is among the exceptions.

The company and its partners are considering developing the discovery as a subsea field connected to a floating production and storage vessel, and may also tie in the smaller Gohta find, which is located nearby.

Prior to the production test the combined gross resource range for the Alta and Gohta discoveries was estimated at between 115 and 390 million barrels of oil equivalent.

“These positive results are expected to increase the Alta resource estimate and reduce the uncertainty range,” Lundin said on Tuesday.

“We have significantly advanced our understanding of this complex carbonate reservoir, the development of which would be a first for Norway. We will now concentrate our efforts on further defining the route to commercialisation and progressing development concept studies,” it added.

Lundin holds a 40 percent stake in Alta, while Idemitsu Petroleum and DEA hold 30 percent each. Lundin also holds 40 percent at the nearby Gohta, while Aker BP holds 60 percent.

https://uk.reuters.com/article/lundinpetroleum-oil/lundin-petroleum-says-arctic-oil-test-points-to-bigger-reservoir-idUKL8N1WB15R

China says there is "huge potential" for Australia's liquefied natural gas (LNG) industry from its trade war with the US after imposing tariffs on rival American imports of the important energy source being encouraged by Beijing to clean up pollution.

China has imposed import tariffs on US LNG imports as part of its latest $US60 billion worth of tariffs in response to US President Donald Trump's latest round of tariffs.

A senior Chinese trade official on Tuesday suggested this could benefit Australia and other countries exporting LNG to China.

"The US could be a major supplier of LNG to China. But because of the trade restriction measures the US imposed, China is compelled to adopt counter-measures. Therefore for the US LNG producers there will be an impact to their exports to the major market of China," Wang Shouwen, China's vice-minister of commerce told a press conference.

"Australia is also an important source of China's LNG import and the trading volume between China and Australia is pretty sizeable and there is huge potential. China is a huge market and China is ready to further expand the market. If there is no trade war, China will offer opportunities to all LNG suppliers and countries."

Analysts have predicted the escalation of trade tensions between China and the US could lift demand for LNG from Australia, which is the world's second-biggest LNG exporter.

China has several long-term purchase deals, including with Chevron's Gorgon and the Woodside-run North West Shelf venture in Western Australia, and two of the Gladstone projects. China is also a potential customer for new export projects, including Woodside's Browse and Scarborough projects, and for an expansion in Papua New Guinea.

The official, who was speaking at a press conference where China outlined its response to Mr Trump's latest $US200 billion round of tariffs, did not elaborate.

Chinese officials on Tuesday downplayed fears about the impact of  a prolonged trade war with the US on the country's economy, saying the risks were under control as the central government expand domestic demand.

The officials also said Beijing was open to resuming trade talks with Washington but only if there was "mutual respect".

"China does not want a trade war but we are not afraid of one. We have the confidence, capability and determination to handle all of risks and challenges. No exterior factor can stop the development of China," Fu Ziying, China's Vice-Minister of Commerce said.

The US and China imposed fresh tariffs on each other's goods on Monday, as the world's biggest economies showed no signs of backing down. The Chinese officials on Tuesday were answering questions about a white paper released the day before when Beijing accused the US of engaging in "trade bullyism".

US tariffs on $US200 billion worth of Chinese goods and retaliatory tariffs by Beijing on $US60 billion worth of US products took effect at midday on Monday in Asia, though the initial level of the duties was not as high as earlier feared. The two countries have already slapped tariffs on $US50 billion worth of each other's goods earlier this year.

https://www.afr.com/news/world/asia/china-says-huge-potential-for-australian-lng-industry-from-us-trade-war-20180925-h15tp5

Oil and gas major Total , said on Tuesday it expected deepwater oil and gas operations to make a strong contribution to its output and cash flow thanks to major developments in the West Africa’s Gulf of Guinea region, Brazil and U.S. Gulf area.

Production from deepwater projects is expected to reach 500,000 barrels of oil equivalent per day (Kboe/d) by 2020, contributing to its 6 to 7 percent output growth target per year from 2017 to 2020.

“Deepwater is today for us a growing and very profitable part of the portfolio,” Total’s President for Exploration and Production Arnaud Breuillac, told investors in New York.

Deepwater production will increase to more than half a million barrels of oil per day by 2020 with cash flow from operations at over $30 per barrel at an oil price of $60 per barrel, Breuillac said.

“Deepwater is approximately 15 percent of the group’s production but it will contribute to more than 35 percent of cash flow from operations in the coming years,” he said during a presentation.

Total’s deepwater projects on the West African coast includes Moho Nord in Congo, Kaombo North in Angola which began production in July. Production is expected to start at its Nigeria’s Egina field by the end of the year, and at Kaombo South by the summer of 2019.

Breuillac said the French company had a number of significant projects in pipeline in Brazil’s “pre-salt” or deep offshore projects, including Lapa, Libra and Lara projects which could add around 100 kboe/d by 2022.

In the Gulf of Mexico, the Ballymore giant discovery is being appraised, while production and more developments were ongoing at its Jack and Tahiti operations.

Total is also exploring in several new deep water areas in Guyana, Mauritania and Senegal, and in South African and Namibia.

“We have a strong deepwater exploration portfolio with numerous drill targets in large areas, targeting significant areas to be drilled in the next two to three years,” Breuillac said.

https://uk.reuters.com/article/total-investors-deepwater/total-sees-cash-flow-output-boost-from-deepwater-projects-idUKL8N1WB6AR

Oil truck drivers in Iran have started a new strike demanding improved working conditions, and the industrial action has resulted in large lines forming at gasoline stations in Iran, The Middle East Monitor reports, quoting the Anadolu Agency and local media.

The strike is the second that truck drivers in Iran have staged this year, after a prolonged strike action in May in which they protested against rising costs for insurance, repairs, spare parts, and tolls, while their wages were stagnant. Back in May, the government has reportedly agreed to raise the pay for truckers by 15 percent, VOA reported.

According to The Middle East Monitor, nothing has been done yet to meet the truckers’ demands from May.

The latest industrial action by oil truckers in Iran comes less than two months after the first set of U.S. sanctions on Iran snapped back, and just six weeks before the second round of sanctions, including on Iran’s key revenue source—oil exports—kick in.

Over the past few months, Iran’s economy has faltered, and its currency, the rial, hit a new low this week against the U.S. dollar on the unofficial exchange rate.

According to data compiled by U.S. economist Steve Hanke of Johns Hopkins University, Iran’s annual inflation rate as of Monday was 293 percent—an all-time high.

The economic hardships are causing a surge in the price of goods, including diapers. Shortages of goods also abound, with Iranian authorities conducting raids to confiscate illegal hoards of rare and costly items such as diapers.  

https://oilprice.com/Latest-Energy-News/World-News/Fuel-Supplies-Tight-As-Oil-Truck-Drivers-Go-On-Strike-In-Iran.html

ADNOC said on Wednesday that the contract is valued at AED 3.16 billion ($860 million) of which around half will flow into the local economy through ADNOC’s focus on maximizing in-country value.

The agreement, between ADNOC LNG and the Technicas Reunida and Target Engineering Construction Company joint venture, was signed by Fatema Mohamed Al Nuaimi, Acting CEO of ADNOC LNG, Arthur Crossley Sanz, General Manager of Tecnicas Reunidas and Chaouci Yassine, CEO of Target Engineering Construction Company.

After the signing ceremony, Al Nuaimi said: “This agreement is a significant milestone as we work across the gas value chain to further integrate our offshore and onshore gas systems to deliver greater efficiency and performance and enable us to maximize the value of our gas assets and pursue our strategic objective to ensure a sustainable and economic gas supply to meet Abu Dhabi’s growing energy needs.”

Second phase of IGD-E

According to the company, the second phase of the Integrated Gas Development Expansion (IGD-E) project will take 54 months to complete. It will add 245 million cubic feet per day of associated gas to the 1.4 billion cubic feet per day of offshore gas sent from Das Island to ADNOC Gas Processing’s Habshan gas facilities to be processed for use in power generation.

The full scope of the contract encompasses engineering, equipment and material supply, construction, installation, testing and commissioning of compression, drying and gas treatment units, as well as power generation and other auxiliary services. It includes the construction and commissioning of new gas facilities on Das Island including construction of a new Booster Compression Train with a capacity of 60 million cubic feet per day, as well as two Feed Gas Compression and Dehydration Trains, each having a capacity of 123 million cubic feet per day and two amine-based Fuel Gas Treatment Units with 80 million cubic feet per day capacity each.

Tecnicas Reunidas will lead the consortium and carry out the engineering and procurement for the project, while Target Engineering Construction Company will lead the construction and commissioning works on Das Island.

Work on ADNOC’s AED 40 billion ($11 billion) Integrated Gas Development program began in 2009, to enable the transfer of one billion cubic feet a day of high-pressure gas from the offshore Umm Shaif field, via Das Island, to ADNOC Gas Processing’s onshore facilities at Habshan and Ruwais. The program was completed in 2013.

Subsequently, Phase 1 of the Integrated Gas Development Expansion project was launched in 2015 and completed last month, boosting ADNOC’s offshore gas processing capacity by 400 million cubic feet per day to 1.4 billion cubic feet per day.  Phase I included the construction of a 4th gas dehydration unit and dry gas compression aftercooler on Das Island; gas pipelines, with a 117 kilometer offshore segment and 114 kilometer onshore segment; condensate pipelines and modifications to the Habshan gas processing complex.

https://www.offshoreenergytoday.com/adnoc-hands-out-860m-worth-deal-for-gas-development-expansion-project/

A dispute over the source of methane emissions in the Barnett Shale was one of the first battles between shale producers and environmental groups. According to a new report from the University of Texas, the methane found in the Barnett was naturally occurring and unrelated to shale gas drilling.

The primary fight in north Texas had to do with methane emissions in groundwater wells. Environmental groups accused producers of causing higher-than-anticipated emissions in wells, a stance that was originally supported by the US Environmental Protection Agency under the Obama administration. The EPA filed an "imminent and substantial endangerment finding" against Range Resources in 2010, blaming the company for the methane emissions. That finding was disputed by Range and the Railroad Commission of Texas, which regulates oil and gas production, and was withdrawn in 2012.

The study, which was completed by researchers from the University of Texas and the University of Michigan, found that Range and other frackers had nothing to do with the methane emissions.

"The methane appears to have migrated naturally to the wells from the shallower Strawn formations and not from the Barnett Shale, where natural gas production and hydraulic fracturing are occurring," the University of Texas said in a statement.

The study, published in Water Resources Research, is the fifth and final in a series by the two universities. It found that the "vast majority" of more than 450 wells across 12 counties in the Barnett region have little to no methane in the water, but a grouping of 11 wells near the Parker County/Hood County line had methane above 10 mg per liter of water.

Researchers used the chemistry of dissolved gasses in groundwater to identify their likely sources. The latest study looked at nitrogen gas to determine the origin of the methane and found that it was naturally occurring.

https://www.spglobal.com/platts/en/market-insights/latest-news/natural-gas/092518-barnett-shale-methane-emissions-in-water-not-linked-to-fracking-study-finds

EQT Midstream Partners boosted the expected cost of its Mountain Valley Pipeline again, this time by about $1 billion, in the latest example of how bad weather, regulatory hurdles, schedule delays and environmental mitigation measures are affecting the US natural gas sector.

The operator said that it has increased its overall project cost estimate to $4.6 billion. A spokeswoman said Tuesday that is up from the most recent estimate in July of $3.5 billion to $3.7 billion. When the project was announced in fall 2015, EQT Midstream had estimated the 2 Bcf/d pipeline would cost $3 billion to $3.5 billion to build.

The cost overruns come as the market awaits more takeaway capacity out of the US Northeast's prolific Appalachian Basin. The approximately 300-mile pipeline is seen as a key conduit to serve downstream markets, including LNG exports. During an investor conference call at the time of the previous cost estimate, executives said expenditures above $3.5 billion would start to eat into expected investment returns.

"The halting of construction due to court challenges from environmental opponents have caused lengthy project delays, material cost increases, and burdens for local communities and agencies; and have also impeded the delivery of low-cost energy resources to consumers and other end-user markets." the operator said in a statement.

Approximately half of the latest cost increase is due to extended periods of work stoppage during August that triggered ongoing contractual charges and schedule changes, the operator said. MVP also blamed significant rainfall throughout the summer and recent hurricane preparedness actions that interrupted full-construction activities, as well as certain unanticipated construction cost overruns. Earlier this month, Hurricane Florence battered a large swath of the East Coast.

MVP maintained its current target of full in-service during the fourth quarter of 2019.

MVP -- designed to transport gas to markets in Virginia and North Carolina -- is a joint venture of operator EQT Midstream, WGL Midstream, RGC Midstream, Con Edison Transmission and an affiliate of NextEra. Shippers include WGL Midstream, Roanoke Gas and EQT Energy, the marketing unit for gas producer EQT.

In April, EQT Midstream proposed to add an offshoot from MVP, called Southgate, that would extend about 70 miles south from the mainline to new delivery points in North Carolina and service customers of utility PSNC Energy with Appalachian Basin natural gas. The company has said it expects MVP Southgate to start up in late 2020. The US Federal Energy Regulatory Commission cleared MVP to restart full construction on August 29, with the exception of approximately 25 miles of the route. The operator said in its statement that based on the current construction plan, MVP expects to complete more than 50% of the pipeline by year-end.

"Along with the work stoppage, significant costs have been incurred to enhance and repair erosion and sediment control devices due to unprecedented rainfall in West Virginia and Virginia during the past several months," the operator said.

MARKET CHALLENGES

Other pipeline operators in North America also have faced meaningful cost increases for gas pipeline projects over the last year.

In August, TransCanada boosted the cost estimate for one of of its Mexico gas pipelines.

The Tula Pipeline is a key piece in Mexico 's expanding gas network. This will allow gas coming from TransCanada and IEnova's 2.6 Bcf/d South Texas-Tuxpan marine pipeline, also known as Sur de Texas, to flow into central Mexico. When the contract was awarded in 2015 to build Tula, it was expected to cost $500 million. The current cost estimate was pegged at $700 million.

That pipeline also has faced delays.

In April, TransCanada said its projected costs for two US natural gas pipeline projects on its Columbia system had increased by about 15% due to regulatory delays and higher construction-related expenses.

Besides higher costs from construction, regulation and bad weather, some US operators that are proposing new gas pipelines also face the prospect of added costs due to tariffs on imported steel from certain countries, including Greece, Canada and Turkey.

https://www.spglobal.com/platts/en/market-insights/latest-news/natural-gas/092518-mvps-latest-cost-increase-a-big-one-expected-to-eat-into-operators-returns#article0

Production of liquefied natural gas (LNG) in Russia could jump to 83 million tons per year by 2035, according to the energy ministry’s Alexander Gladkov.

Speaking during an energy conference, the head of the energy ministry’s oil and gas production and transportation department, said the country’s production capacity could be increased from the current 21 million tons per year, TASS reports.

He added that the ministry is focused on providing incentives to aid the industry’s development, saying that potential approaches are being considered in order to stimulate the industry.

Currently, the country has a 4 to 5 percent share in the global LNG market. He noted that by 2035 this share could be bumped significantly up to 15 to 20 percent.

The 21 mtpa of LNG Russia currently exports are produced by two projects, the Sakhalin II project operated by Sakhalin Energy, a joint venture between Gazprom, Shell, Mitsui and Mitsubishi, and the Novatek-operated Yamal LNG.

https://www.lngworldnews.com/russias-annual-lng-production-capacity-to-hit-83-mtpa-by-2035/

Oman’s Renaissance Services SAOG, a service provider to the oil and gas industry, is considering an initial public offering for its Topaz Energy & Marine unit, according to people familiar with the matter.

Renaissance, which has a market capitalization of about $379 million, could seek a valuation of about $1.5 billion for the Dubai-based business, the people said. Goldman Sachs Group Inc. and Morgan Stanley are advising on the share sale, which could take place next year in London, said the people, asking not to be identified as the details aren’t public.

Valuation and location are still being discussed and no final decisions have been made, the people said. Renaissance may also choose to retain its stake in the division for now, they said. Renaissance had abandoned a London IPO of the unit in 2011 and considered selling it a year later. Topaz raised $203 million in May to refinance its debt.

A representative for Renaissance couldn’t immediately be reached. Spokesmen for Goldman Sachs and Morgan Stanley declined to comment. A representative for Topaz pointed to a statement by Chairman Samir Fancy in the 2017 annual report and declined to comment further.

“Topaz and its shareholders believe that it is the right time to consider the company’s strategic options in relation to growth and capital enhancement,” Fancy wrote at that time. “All options are being considered, including inorganic and capital market transactions such as an offering of securities,” though no decisions have been made, he said.

First-half earnings before interest, taxes, depreciation and amortization rose 33% from a year earlier to $77 million, according to Topaz. The offshore support vessel and marine logistics company said a key reason for the upswing was a turnaround of its African business in a buoyant market.

https://www.worldoil.com/news/2018/9/25/omans-renaissance-is-said-to-mull-15-billion-topaz-energy-ipo

French oil and gas major Total has made a final investment decision to expand its Texas Bayport Polymers joint venture to double polyethylene production capacity to around 1.1 million tonnes a year, the company said.

Total said it aimed to become a major player in the U.S. polyethylene market when it announced the joint venture in March 2017 with Borealis and Canada’s Nova Chemical.

The Bayport project is in line with the company’s $3 billion program that began a year ago with a $1.7 billion investment to build an ethane steam cracker at its Port Arthur refining complex in Texas.

The cracker will process ethane, which is abundantly available from U.S shale gas at competitive prices, and will supply Bayport polyethylene units. Production is expected to start in 2021.

The new unit is expected to have a capacity of a 625,000 tonnes a year, that will added to the existing 400,000 tonnes per year unit.

The Bayport unit engineering, procurement and construction has been awarded to the company McDermott, Total said.

Polyethylene is used in packaging, pipes, bottles, plastics and other composite materials. It is also seen as a growing market, that Total is targeting with a global expansion of its petrochemicals refining units.

“The project is in line with our strategy to develop petrochemicals at our major integrated (refining) complexes and leverage competitively priced feedstocks,” said Bernard Pinatel, Total’s President for Refining and Chemicals.

Pinatel said light materials are increasingly used as substitutes for metals in various industrial sectors such as transport and energy, all of which is lifting demand for plastics and polymers.

“It is a market that is growing by 3 to 4 percent per year,” Pinatel said.

As part of this expansion into the polyethylene market, Total and Saudi Aramco had said in April they would invest around $5 billion to build a petrochemical complex at their Jubail Satorp refinery.

In May, Total also signed a $1.5 billion deal with Algeria’s Sonatrach to build a polypropylene plant in western Algeria that will supply plastic to the Algerian and wider Mediterranean market.

Last December, its South Korean joint venture with Hanwha Group had also said it would invest $331 million in the group’s refining and petrochemicals platform to increase polyethylene output by 400,000 tonnes per year by 2019.

That increased investment was planned to deal with growing demand, particularly from China.

https://www.reuters.com/article/us-total-petrochemicals-bayport/total-finalizes-plans-to-expand-texas-bayport-polymers-in-petrochems-push-idUSKCN1M51Y5

Santos to produce 100 mboe by 2025, double current production

Australian LNG player Santos has set its sights on growing the production figures to over 100 million barrels of oil equivalent by 2025.

This would almost double the current production volumes, the company said in a statement.

Speaking at the company’s Investor Day in Sydney, Santos managing director and CEO Kevin Gallagher noted that the company’s strategy unveiled in 2016 has given it the opportunity to target said production levels.

The strategy included the sale of non-core assets and free cash flow at a barrel oil price below $40.

“We are now positioned for disciplined growth leveraging existing infrastructure in all five of our assets in the portfolio and are targeting production of more than 100 mmboe by 2025,” Gallagher said.

Santos’ growth portfolio includes Barossa backfill to Darwin LNG, PNG LNG expansion and the proposed farm-in to P’nyang, Cooper Basin, GLNG and Eastern Queensland options and well as the Quadrant acquisition that includes Dorado oil discovery.

Gallagher noted that following regulatory approvals and the completion of the Quadrant acquisition, Santos’ breakeven oil price would be reduced further.

https://www.lngworldnews.com/santos-to-produce-100-mboe-by-2025/

Qatar Petroleum, the world's top supplier of liquefied natural gas (LNG), said on Wednesday it was adding a fourth liquefaction train to raise capacity from the North Field to 110 million tons per annum (MTPA). The output from the field will rise from 77 million tons a year now.

With the addition of the fourth train, the new project will produce about 32 MTPA of LNG, 4,000 tons/day of ethane, 260,000 barrels/day of condensate, and 11,000 tons/day of LPG, in addition to approximately 20 tons per day of pure helium.

When the project is completed, Qatar’s LNG production capacity will reach 110 MTPA, representing an increase of around 43% from its current production capacity of 77 MTPA.

The announcement was made by Saad Sherida Al-Kaabi, the President & CEO of Qatar Petroleum, who said: "As we have announced last year, Qatar Petroleum has embarked on a project to develop additional gas from the North Field and build three new LNG mega trains. Based on the good results obtained through recent additional appraisal and testing, we have decided to add a fourth LNG mega train and include it in the ongoing Front-end engineering of the project. When the project is completed and all four new trains are online, Qatar’s LNG production capacity will reach 110 MTPA. This will increase Qatar’s total production capacity from 4.8 to 6.2 million barrels of oil equivalent per day."

Al Kaabi added, "This new capacity increase will further strengthen our leading position as the world's largest LNG producer and exporter, and will further boost Qatar Petroleum's strategic growth plan. This production addition will have a great impact on Qatar’s economic growth and will help stimulate our local economy."

Al-Kaabi concluded his comments by saying “We believe that LNG has bright prospects and that the new expansion project reflects Qatar Petroleum’s commitment to meeting its worldwide customers’ growing needs for this reliable and environmentally friendly fuel.”

The North Field Expansion Project is well underway with various activities currently ongoing, including the Front End Engineering and Design (FEED) of the onshore facilities, which is being executed by Chiyoda Corporation of Japan. The engineering, procurement, construction and installation (EPCI) contract for the offshore wellhead jackets is expected to be awarded before the end of the year, and development drilling activities are expected to commence imminently.

https://www.thepeninsulaqatar.com/article/26/09/2018/Qatar-Petroleum-to-increase-LNG-production-capacity-with-new-train

Pioneer Energy Services Corp. cut its outlook for international drilling utilization, citing unexpected unpaid standby time, and lowered its production services revenue and gross margin guidance ranges because of softer-than-anticipated activity.

The company disclosed that it now expects international drilling utilization of 76% to 80%, down from previous guidance of 85% to 87%. Production services revenue guidance is now expected to decline 5% to 7% versus previous expectations of a 3%-to-5% decline and gross margin as a percentage of revenue is now expected to be 21% to 23% compared with previous expectations of 23% to 25%.

The stock has tumbled 35% over the past three months, while the SPDR Energy Select Sector ETF XLE, has gained 2.8%

https://www.marketwatch.com/story/pioneer-energy-services-cuts-outlook-on-lower-than-expected-activity-2018-09-26

Royal Dutch Shell Plc and its partners are set to announce a decision on their C$40 billion ($31 billion) liquefied natural gas terminal in western Canada as early as next week, amid signs the companies are poised to approve it, according to people familiar with the plans.

Preparations for an Oct. 5 announcement followed by an LNG Canada event and fireworks at the local golf club the next day are underway in Kitimat, British Columbia, the site of the proposed project, said people with direct knowledge of the activities, who asked not to be identified. The situation is fluid and timing could change, the people said.

LNG Canada -- backed by Shell, Mitsubishi Corp., Malaysia’s Petroliam Nasional Bhd., PetroChina Co. and Korea Gas Corp. -- would be Canada’s largest-ever infrastructure project. With the capacity to eventually export as much as 26 millions tons per year, primarily to Asia, it would also be the largest new LNG terminal to be sanctioned in years.

“We are currently reviewing the decision support package that LNG Canada submitted to joint venture participants," Shell Canada said in emailed response to questions late Tuesday. Shell declined to comment on the announcement date and whether a final decision has been made.

The group has long said an investment decision will be made this year. British Columbia has set a Nov. 30 deadline for a final decision if the project is to claim as much as C$6 billion in tax breaks and savings.

Trade relief

The project may also get a boost from the Canadian government in the form of tariff relief, the Globe and Mail reported Wednesday. The government has agreed to waive import duties on steel needed for the terminal, saving the companies about C$1 billion, the paper said, citing people familiar with the plan. The LNG group had sought relief from the duties, arguing that the steel for the massive terminal couldn’t be sourced in Canada. The government is now confident the operators will give the project a green light this year, the Globe said.

“We are hopeful that Shell will make a positive investment decision which will lead to the creation of thousands of jobs,” said Pierre-Olivier Herbert, spokesman for Finance Minister Bill Morneau. “There is due process in place for the remission of surtaxes in the event that there is no domestic supplier, and that process must be followed.”

Prime Minister Justin Trudeau met with Royal Dutch Shell CEO Ben van Buerden in New York Tuesday.

The LNG decision was put off twice in 2016 amid a global supply glut, but the outlook for LNG has brightened. LNG imports will set a new record this year of 308 million metric tons per year, up 8.5 percent since 2017, Bloomberg New Energy Finance forecast on Sept. 12. Half of that growth will come from China and the remainder largely from Japan, South Korea and India, the London-based researcher said.

"The overall conditions for LNG Canada to go ahead in 2018 are quite good," Andy Calitz, CEO of the project, said in an interview in Vancouver this month. "That is, and feels, so very different to 2016 when the project was delayed."

LNG Canada would be a welcome boost for Canada’s energy sector. In May, Trudeau agreed to pay C$4.5 billion to buy the Trans Mountain oil pipeline from Kinder Morgan Inc. after the company balked at proceeding with construction. In August, the Federal Court of Appeal nullified approval of the project. All that follows years of tortured regulatory reviews -- 35% of Canada’s proposed LNG capacity has been canceled and an additional 40% is under review, Bloomberg New Energy Finance said in a Sept. 10 note.

https://www.worldoil.com/news/2018/9/26/shell-canada-poised-for-lng-decision-as-early-as-next-week

Unite workers on three North Sea platforms have accepted a pay deal, bringing an end to a protracted strike dispute.

Workers on Total’s Elgin, Alwyn and Dunbar platforms have accepted a 15% pay increase but will move to three weeks on, three weeks off (3/3) rotas for going offshore.

A series of 12-hour and 24-hour strikes have been carried out on the platforms since July over the dispute which centres on the 3/3 rotas, which Unite previously described as “hated”.

The new deal, which also includes “substantial” retention bonuses, means all future action on the rigs has been called off.

Total plans to move workers to the 3/3 rota in January next year.

61.9% of workers voted in favour of the new pay offer, in a 93% turnout.

Unite said it maintains “serious concerns” over the rotas, but Total said it is a “safe rota” which is commonly worked in the sector.

A Robert Gordon University (RGU) report published earlier this year claimed those on 3/3 rota are almost twice as likely to experience ill health in comparison to those on 2/2 shifts.

Total wanted to implement 3/3 across its North Sea business following the acquisition of Maersk Oil earlier in the year and said it is “necessary” to the operator’s long-term business in the UK.

Wullie Wallace, Unite regional industrial officer, said: “Unite members have accepted the latest offer by Total on the basis of securing a number of significant improvements from the previous offer.

“This has been a long and protracted dispute following months of negotiations but we have secured a significant victory with a 15 per cent base increase and a substantial bonus for the workforce.”

“Unite retains serious concerns over the 3/3 rota system, which we will monitor.”

A spokesman for  Total said it means a “bright future” in the UK North Sea, following news of its major Glendronach gas find west of Shetland earlier this week.

He said: “We’re pleased that our workforce has accepted the company’s offer and that this will bring industrial action offshore to an end.

“The 3/3 rota is necessary for the long-term future of our business in the UK.

“It is a safe rota that is commonly worked throughout the North Sea and the wider global oil and gas industry.  The new rota will preserve the long-term sustainability of our business in the North Sea, which remains one of the most expensive locations to operate in the world.  We aim to move to the 3/3 rota by Jan 2019.

“Total E&P UK has a bright future.  This week we announced discovery of the Glendronach reservoir, the completion of our major project Culzean is on track for next year and we also have an exciting exploration programme for the future. “

https://www.energyvoice.com/oilandgas/north-sea/182479/breaking-pay-deal-brings-end-to-north-sea-strikes/

Beach Energy has buoyed investor sentiment with a target to build on its acquisition of Lattice Energy and take production up to as much as 40 million barrels of oil equivalent (boe) within five years with a focus on high-returning ventures in the tight east coast gas market.

Shares in the mid-cap oil and gas producer jumped as much as 10 per cent after chief executive Matt Kay told investors and analysts he saw "a very exciting period of growth" over the next few years, centred around the company's existing Cooper Basin fields as well as the several ventures acquired through Lattice.

About 60 per cent of Beach's gas reserves are exposed to the east coast gas market, where prices have soared over the past two years.

Free cash flow of more than $2.3 billion is targeted over five years, with production increasing to 34 million-40 million boe by 2022-23, according to material presented to investor briefings in Sydney.

Production is set to rise to 34 million-40 million barrels by 2023. Beach Energy

Mr Kay said that while the production growth goals partly depend on drilling results, the targets are solid and are based only on Beach's existing ventures, leaving scope for upside.

"There is no blue sky or hypothetical in any of these numbers," he told an investor briefing in Sydney.

Mr Kay said Beach expects to be "close to debt free" by the end of 2019-2020, which he described as "a remarkable achievement" considering net gearing stood at 33 per cent at the end of January when the company completed the $1.585 billion acquisition of Origin Energy's conventional oil and gas business, Lattice.

Beach surprised investors last month when it announced a heavier-than-expected level of capital spending for 2018-19, but Mr Kay noted that only 7 per cent of that was linked to production this financial year, with the rest to drive reserve growth and underpin future production expansion.

Beach is targeting cumulative cash flow of at least $2.3 billion over the next five years. Beach Energy

Some 89 per cent of the circa $2.8 billion expected to be invested by Beach over the next five years is discretionary, with more than two-thirds of that achieving rates of return of 40 per cent, Mr Kay said.

He said that over the next five years return on capital employed by Beach would be at a "world class" level of between 17 per cent and 20 per cent.

"More than three quarters of our discretionary investment will be directed towards bringing new supply into the market over the next five years, where we already have a 15 per cent market share," Mr Kay added.

Beach's output in 2017-18 was 19 million boe, which is expected to jump to 26 million-28 million boe this year with the addition of Lattice.

https://www.afr.com/business/energy/oil/beefedup-beach-energy-eyes-expansion-to-40m-barrels-output-20180926-h15wy9

Aker Solutions has signed a strategic, global collaboration agreement with Equinor to ensure mutual and continuous improvement on current and future subsea projects within the domains of safety, quality, technology, execution and cost.

"Aker Solutions and Equinor's ongoing collaboration has consistently generated mutually beneficial technology developments, working process simplifications and standardizations," says Luis Araujo, chief executive officer at Aker Solutions. "This agreement formalizes the companies' joint ambitions of achieving efficiency and improvement goals."

Several innovative and cost-efficient solutions have materialized from Aker Solutions' and Equinor's history of collaboration. Aker Solutions' newest subsea production system with vertical trees and associated tools were developed in close collaboration with Equinor, designed to be more efficient and reduce life-cycle costs. The subsea equipment is smaller and lighter than previous versions and has now become Equinor's standard solution. As well as adopting this technology on the Johan Castberg field, Equinor will use trees of the same design on its Troll and Askeladd fields offshore Norway and they have also been commissioned by other operators on the Norwegian Shelf, including Aker BP for the Ærfugl development.

https://www.worldoil.com/news/2018/9/26/aker-solutions-strengthens-collaboration-with-equinor

U.S. LNG exports have climbed from zero three years ago to more than 3 Bcf/d now, and export capacity is set to grow to more than 10 Bcf/d by 2023. With the U.S. emerging as a dominant player in the global LNG landscape, international players are now increasingly susceptible to the day-to-day fluctuations of the U.S. natural gas market — a highly liquid, fungible and interconnected arena that’s propelled by constantly shifting transportation economics. The global LNG market inevitably is also moving toward spot-oriented trading based on short-term economic conditions. Thus, prospective buyers of U.S. LNG considering pre-FID projects increasingly need to understand the ever-changing U.S. gas flow and pricing dynamics. At the same time, U.S. market participants trying to understand how 10 Bcf/d of LNG exports will affect the domestic market also will need to closely track LNG activity, including feedgas flows and prices. In today’s blog — which launches our new LNG Voyager service — we look at how U.S. onshore gas market dynamics are affecting gas supply costs at the Sabine Pass LNG facility, and considers what this might mean for several of the pre-FID projects.

As you’ve probably figured out by now, today’s blog is a naked advertorial for our new LNG Voyager service, a report featuring U.S. natural gas and LNG insights for the global market. Before we get to our analysis, allow us a moment here to provide a bit of background about this new report. Given the significance of the burgeoning U.S. LNG exports market — both to domestic and global trade — we’ve developed a comprehensive fundamentals tool to closely track the metrics, milestones and impacts of these shifts as they unfold. The LNG Voyager Weekly report combines fundamental data, graphs and analysis to provide a full picture of the factors impacting the U.S. LNG supply chain, including upstream production trends in the Haynesville, Marcellus/Utica and Permian; pipeline capacity; Louisiana and Texas Gulf Coast flows and price dynamics; terminal operations; and destinations. A quarterly supplement also provides detailed updates on the liquefaction and pipeline projects that are driving the market shifts, including project timing, capacity contracts and supply contracts.

With perennially low gas prices and more supply potential than the market knows what to do with, the start-up of six U.S. liquefaction projects has been of paramount importance. We’ve devoted not just a single blog but a whole blog series to Sabine Pass feedgas flows, the resulting changes in flows into and out of Louisiana, and, most recently, to some of the Gulf Coast projects vying to take a final investment decision (FID). And when we previewed our new LNG Voyager offering earlier this summer, we also showed how a pipeline outage in the Northeast could affect liquefaction plants all the way down on the Louisiana Gulf Coast.

But as we alluded to above, this is just the beginning. There are four more projects on the way. Additionally, there are more Northeast takeaway pipeline expansions in the works that will allow Marcellus/Utica production to balloon to nearly 40 Bcf/d over the next five years, up from about 29 Bcf/d currently, with a major chunk of that incremental volume targeting LNG export demand along the Gulf Coast (see Dog Days Are Over). Feedgas pipelines are feeling the growing pains of the influx of gas supply, with constraints developing on existing capacity. As the market adapts to the new realities that come with rising export demand, the global LNG market will face growing exposure to the day-to-day volatility of the U.S. gas market.

Understanding the resulting flow and price movements will be critical for prospective LNG buyers considering different pre-FID projects, as well as for U.S. market participants trying to comprehend how 10 Bcf/d of LNG exports will affect domestic flows — and everyone in between. That brings us back to our analysis of how domestic market dynamics are shaping the delivered costs of gas supplies to the terminals. Delivered costs are a key metric for determining the economics of one supply route over another for LNG buyers looking to optimize feedgas flows into their liquefaction capacity. With the first four trains at Sabine Pass Liquefaction (SPL) up and running, and the fifth on the way, we now have enough data to render some early judgments about U.S. Gulf Coast LNG operations. The LNG Voyager Weeklyclosely tracks SPL’s pipeline capacity, including the six key hubs accessed by the six different pipelines routing gas to the facility, each with its own different drivers and dynamics. The takeaway from our analysis of this data is that even though flows into the plant are relatively stable across routes, the delivered cost of gas at the terminal is subject to considerable swings from one week to the next, and sometimes even day-to-day.   

One significant caveat to keep in mind in the case of SPL is that the liquefaction capacity holders have contracted at fixed cost and Cheniere is obligated to secure feedgas for its customers. Thus, Cheniere takes both the upside and the downside if feedgas prices are different from the sales price formula. Conversely, most other LNG export terminals charge a fee for liquefication and loading, with the customer responsible for showing up at the terminal with the gas — a requirement that comes along with both risks and opportunities. For analyzing feedgas supply dynamics, that’s the difference between the terminal operator purchasing the gas (as in the case of SPL, along with Cheniere’s other project under construction, Corpus Christi Liquefaction), versus gas being purchased by the individual LNG exporting companies — as is the case with the other liquefaction plants. Nevertheless, since the goal for both is to deliver the feedgas as economically as possible, we don’t have to wait until those facilities start up to begin to draw some conclusions about how those markets may function. The price movements and transportation costs that can be analyzed today are representative of how the domestic and global markets will interact at the other terminals where LNG offtakers will be looking to optimize their feedgas options. For existing and potential US LNG offtakers, and for US gas market participants, understanding how the ongoing liquefaction buildout affects these spreads will be of critical importance — especially as existing north-to-south infrastructure within the Gulf Coast region becomes constrained.

To understand gas flows and arrive at the delivered costs, you need to start by knowing who has capacity on which pipelines. Luckily, in the gas market, this is much more straightforward than for NGLs or for crude. By now, even casual readers of the RBN blog are familiar with the daily capacity and flow information available on electronic bulletin boards (EBBs) for all operational interstate pipelines (see Sooner or Later for more on flow data). More under-the-radar, but equally important, is that these operational interstate gas pipelines also must post both their “Index of Customers” data — detailing which companies have firm transmission (FT) rights and from which receipt points to which delivery points — as well as their tariffs, detailing the transportation rates that customers will pay. For interstate pipeline projects that are under construction but not yet operational, they must also file detailed project plans with the Federal Energy Regulatory Commission (FERC). Scanning all of these filings can be like reading Greek to the uninitiated, so we’ve combed through them for our LNG Voyager subscribers.

If we take the critical pieces of information provided in these filings, the end-product is an easier-to-understand schematic map for each terminal, illustrating the key hubs serving the liquefaction facility and the variable costs of moving gas to the plant. Variable cost is what customers pay the pipeline operator based on the actual volume of gas being moved. It is typically the sum of the pipeline’s commodity charge (paid on each unit of gas moved) and the pipeline’s fuel rate, which is the amount of gas turned over to the pipeline operator to run its compressors and move the gas.

Figure 1 below aggregates these key data points for the SPL facility. The solid lines represent routes where SPL has FT capacity, while the dotted lines show some of the relevant additional routes to SPL. The white diamonds show each pipe’s fuel rate and commodity charge (see Living in Fast Forward Curves), i.e., the cost of transporting the gas from the supply hub to SPL. The circles provide the basis — the local price versus Henry Hub — and the netback, or the supply price minus the variable transportation cost, at key supply hubs supporting SPL deliveries.

Figure 1. Sabine Pass Liquefaction schematic. Source: RBN LNG Voyager Weekly

To put a bit more color around this, the schematic shows that there are four primary routes into the terminal, some of which are themselves fed by multiple routes upstream, which, when combined, provide what is called “stacked capacity” to the terminal, for the uninitiated. We detail all this capacity and the respective upstream supply agreements in LNG Voyager, but we’ll summarize the high-level points here, along with the relevant hubs and variable costs:

Creole Trail (the short solid purple line on the lower portion of the map) is a Cheniere-owned pipeline on which SPL (the entity that has title to the gas through the liquefaction process) holds 1,530,000 MMBtu/d (or about 1.5 Bcf/d) of FT from Gillis, LA, and costs about $0.02/MMBtu to get to the plant. Creole Trail can take gas from seven pipelines, but in practice has only taken gas from three of them:

Trunkline (hot pink line), where SPL holds 370,000 MMBtu/d (~360 MMcf/d) of FT from Trunkline’s interconnect with Fayetteville Express Pipeline in Bobo Road, MS, and Trunkline’s Zone 1A (hot pink circle). In practice, this means SPL will pay about $0.02/MMBtu to ship gas from the Trunkline 1A hub to Creole Trail.

Texas Eastern Transmission (TETCO; dotted blue line), where SPL does not hold any FT, but where Cheniere does have supply agreements with CNX Resources and EQT, both of whom hold TETCO capacity to Creole Trail. While we cannot know the precise terms of this supply agreement, it’s reasonable to assume that it’s probably at a slight premium to TETCO WLA, since WLA is a receipt price.

Transco (solid and dotted yellow lines), where SPL holds FT but it would be more economic to deliver this gas directly to the plant on Transco, rather than paying the variable costs on Creole Trail (see below).

NGPL (solid green line) from the Mid-Continent, where SPL has 200,000 MMBtu/d (~190 MMcf/d) from an interconnect with MidContinent Express Pipeline. This interconnect is in the TexOk zone (green circle), located (as you might think) near the Texas-Oklahoma border. It costs about $0.03/MMBtu in variable costs to ship this gas to the plant from the NGPL TexOk hub.

NGPL from Henry Hub, where SPL has 350,000 MMBtu/d (~340 MMcf/d) from the Henry Hub (blue circle), which costs about $0.02/MMBtu to ship to the terminal.

Transco, where SPL backstopped the Gulf Trace project, which reversed flow on the line in Louisiana and came online in April 2017. SPL holds 1,200,000 MMBtu/d (~1.15 Bcf/d) of capacity from Transco Station 65 (yellow circle), and this route has variable costs of about $0.03/MMBtu to the plant.

SPL also holds two tranches of Texas Gas Transmission (TGT; light pink line) capacity into Transco. This capacity originates from interconnects with Fayetteville Express Pipeline ($0.03/MMBtu of shipping costs from TGT Z1) and Rockies Express Pipeline ($0.03/MMBtu of variable costs from Lebanon—too far north to fit on this map!) and totals 300,000 MMBtu/d (~290 MMcf/d).

That’s a lot of detailed information, but the high-level takeaway is that SPL is sourcing gas from several different supply hubs and therefore exposed to daily price fluctuations at several different receipt locations. So, what does this mean for the actual cost of gas into Sabine Pass? In Figure 2 below, we plot the basis at each of the relevant hubs for SPL, along with the weighted average-delivered price into the LNG terminal, i.e., the delivered cost (dark blue line in the chart). (This chart shows the seven-day moving average since daily basis trends are noisy.) Most of SPL’s receipts are coming along routes where it has FT (meaning variable costs consist of fuel and commodity charges). But for volumes being shipped interruptible transmission (IT), we have used the average of the minimum and maximum IT rates. Using either the minimum or the maximum does not materially change the result, since the vast majority of gas is shipped FT.

Figure 2: Supply Basis vs. Delivered Cost at SPL. Sources: NGI, RBN Energy

As you can see in this chart, basis at several hubs accessed by SPL has weakened considerably over the last month. This has been especially the case for hubs further north such as Trunkline 1A (orange line), NGPL TexOk (yellow line), TGT Z1 (purple line), and Lebanon (green line), likely because demand began to seasonally decline in most of the country, but the biggest sources of demand on the Louisiana coast (namely, LNG exports and industrial demand) remained strong. And indeed, increasing stress on north-to-south flows within the Gulf Coast is something we’ve been warning about for some time, and something we’ll be monitoring each week in the LNG Voyager report.

As a result, SPL’s “basis” (supply price plus variable costs of shipping the gas to the plant) has fallen from a $0.03/MMBtu premium to Henry Hub on August 15 (2018) to an $0.11/MMBtu discount to Henry Hub on September 13. For September month-to-date, the improvement in feedgas prices from August’s average has been worth about $1.2 million. Now, SPL may have hedged some of these prices before the month, so there’s no way to know the ultimate impact on Cheniere’s bottom line. But, nonetheless, the lesson is telling for all current and potential U.S. LNG offtakers:  That the Henry Hub price does not tell all you need to know about sourcing U.S. gas supply — not even close.

Further, variable costs are only part of the story. Accessing those hubs further upstream required committing to long-term pipeline capacity and paying the corresponding demand charges to secure the FT. And with the Louisiana north-to-south corridor increasingly constrained, the next project won’t be a simple reversal of a compressor station. Indeed, in conjunction with its Driftwood LNG project, Tellurian has proposed building bullet pipelines from each of the Permian and Haynesville areas to its Lake Charles, LA, site. But this gas sourcing question is something that should be front of mind for any potential U.S. LNG offtaker, as these dislocations are only likely to get larger as more and more Gulf Coast LNG terminals come online.

https://rbnenergy.com/smooth-operator-understanding-chenieres-sabine-pass-feedgas-helps-evaluate-future-lng-projects

The oil and gas fracking boom has lured scores of drillers to the Eagle Ford region of South Texas, the second largest U.S. oil patch, as new production technology opened access to billions more barrels.

The play extends across the Mexican border, where its name changes to the Burgos Basin – an equally fertile shale region where the oil and gas sit mostly idle underground in a region terrorized by criminal gangs.

The violence here threatens to derail the country’s first-ever auction of exploration and production rights to its shale fields in February – one that could prove pivotal to its hopes for reversing a national decline in crude and natural gas output to two-decade lows.

Despite an energy-reform push that has aimed to lure investments from foreign oil firms since 2014, only Mexico’s state-run oil firm Pemex has tried fracking the country’s shale reserves, and only experimentally, even as fields that are accessible with traditional drilling methods are drying up.

The nine shale oil and gas blocks up for auction are all within Burgos, in the northern state of Tamaulipas, where the Gulf and Zeta cartels have waged a war for control of drug and human-trafficking routes since 2010.

As security unraveled, at least two Pemex workers were killed and 16 were kidnapped as gangs demanded protection money from oil firms and blocked work crews from accessing wells and pipelines. A manager with Weatherford International Ltd (WFT.N), the Switzerland-based oilfield services firm, was also murdered.

In April, a Pemex security worker guarding installations against fuel thieves was killed and another was shot in an ambush in the Tamaulipas city of Matamoros after gunmen fired some 60 rounds into a vehicle.

The Burgos Basin contains about two thirds of the country’s technically recoverable shale reserves, estimated at 545 trillion cubic feet (TCF) of gas and 13.1 billion barrels of oil and condensate, compared to the 665 TCF of gas and 58 billion barrels of oil and condensate in the United States, according to the U.S. Energy Information Administration.

Companies that are already fracking across the border in Texas would likely expand into Mexico if the government could address the violence, oil executives said.

Mexican government officials often field questions about security in gatherings where they promoted the nation’s drilling opportunities to oil firms.

“In every meeting I was able to attend, there were questions about security,” said Jorge Rios, vice president of operations for Latin America with Precision Drilling, a Canadian company that operates in the Eagle Ford and has drilled in Mexico in the past. “The response was not firm.”

Mexico’s energy and interior ministries did not respond to requests for comment. Pemex declined to comment.

Repsol (REP.MC), a Spanish oil major, left the Burgos Basin in 2014 as the violence escalated, ending operations it began in 2004 as the first foreign firm to drill in Mexico since it nationalized the industry in 1938. The company, which has shale operations in Eagle Ford, would require “very big changes” before it considered returning to the Burgos, a Repsol executive told Reuters on condition of anonymity.

“In 2014 the situation was difficult to manage,” the executive said. “Now it’s worse.”

Repsol declined to comment through its Mexican public relations agency on the executive’s version of events.

GOVERNMENT SILENCE

Mexico’s natural gas output fell for third year in a row to 4,240 million cubic feet per day last year, increasing the need of imported gas - almost entirely from the United States - to 84 percent of the nation’s consumption. The growing dependence on foreign gas prompted the government to hold a conference for energy companies in the city of Reynosa in Tamaulipas to promote the upcoming shale auction.

The cheerfully-colored Parque Cultural Reynosa conference center was guarded by soldiers and police armed with automatic weapons. But inside the conference in February, panelists carefully avoided any mention of murders or kidnappings. One panelist told Reuters he had specifically been asked by Tamaulipas state officials to avoid mentioning violence.

“The government was in promotional mode. They weren’t going to talk about the bad things,” said another conference participant.

Tamaulipas’ state energy commission and local officials, which helped organize the conference, did not respond to a request for comment.

Security problems were nonetheless top-of-mind for attendees – who were greeted by the news of crackling shootouts in the crime-infested border city. Delegates stayed at a heavily fortified hotel and waited for rides to the conference in armored vehicles guarded by soldiers.

In the days leading up to the conference, about a dozen bodies were left in the streets as cartel linked to the Gulf and Zeta cartels mounted roadblocks and battled security forces. Two weeks before, in the nearby city of Nuevo Laredo, a gun battle broke out within meters of where the mayor was giving a speech.

Another conference participant – a Houston-area businessman – said the Mexican government had taken a head-in-the-sand approach to the violence, one he compared unfavorably to Colombia, where senior security officials showed up at energy conferences a few years ago to reassure investors of progress in fighting armed rebels.

In 2003, Repsol was awarded a service contract by Pemex in the Burgos Basin to develop several conventional natural gas fields along the Reynosa-Monterrey area for 10 years. Repsol increased production at the region after an initial investment of $170 million, but returned the installation to the state-run firm in early 2014.

When Repsol started, the Reynosa region was relatively calm, but within a couple of years it plunged into chaos after President Felipe Calderon went on the offensive against drug cartels. The Repsol executive said oil firms had to guard against kidnappings, extortion and having workers caught in crossfires between rival gangs, along with is now Mexico’s fastest-growing organized crime - fuel theft.

The firm invested in private security, the executive said, but it wasn’t enough.

“That’s what made us leave,” the executive said.

A senior Pemex executive compared the current situation in Tamaulipas to Iraq and Colombia during their years of conflict, saying oil companies could operate with appropriate safety measures.

“You can work, perhaps not as efficiently as we would like, but you don’t lose money, either,” the executive said.

Other companies including Newpek, a unit of Mexico’s Alfa, and a consortium of Mexico’s Jaguar Exploración y Producción with a unit of Canada’s Sun God Resources, came to drill in Tamaulipas state after the 2014 government oil reforms.

By the time they arrived, strict protocols had been introduced by operators and service firms in the area, keeping employees inside between 4 p.m. and 8 a.m. and coordinating with the military before moving into the field.

To avoid dangerous misunderstandings, cars are clearly marked with company logos and employees avoid wearing clothes that the criminals could mistake for security forces, two oil workers told Reuters. They practice defensive driving, move in convoys and are told to respond honestly if interrogated by the cartel.

Women are generally not permitted to work beyond the major urban areas.

“I was not allowed to go into the field because there is a high risk I could be raped,” one female worker said.

Liberty Oilfield Services, whose operations include the Eagle Ford, has not considered operating in Mexico in part because of safety concerns.

“The safety of our workers in Mexico would be a massive concern,” said Liberty Chief Executive Officer Chris Wright. “We’d take some of our own actions for security and guards, but maybe that’s not enough.”

https://www.reuters.com/article/us-mexico-oil-violence-insight/in-mexicos-shale-patch-cartel-violence-scares-off-drillers-idUSKCN1M61F9

China is willing to further open up and will provide more opportunities to liquefied natural gas (LNG) suppliers as a huge market, a senior official said at a press conference conducted by the Information Office of the State Council on September 25.

The US-initiated trade war has damaged the global value chain and inflicted a negative impact on normal trade, said Wang Shouwen, vice minister of commerce and the deputy representative of international trade negotiations.

"The United States is an important supplier of China's LNG. But because the US has imposed trade restrictions, China is compelled to take corresponding measures," said Wang Shouwen when answering a question about the business opportunity for Australian LNG.

"Therefore, for the LNG producers in the United States, their export to China will be affected. This is a fact and has already been shown," Wang added.

"Australia is an important source of LNG for China. The trade volume between China and Australia is sizable, Wang explained. "The Chinese market will provide opportunities for all LNG suppliers."

LNG is natural gas that has been cooled down to liquid form for ease and safety of non-pressurized storage or transport. Taking up about 1/600th the volume of natural gas in the gaseous state, it is odourless, colourless, non-toxic and non-corrosive.

http://www.sxcoal.com/news/4579044/info/en

Marathon Petroleum has increased its capacity to export gasoline and diesel from the Gulf Coast with the purchase by MPLX, its sponsored master limited partnership, of a Louisiana export and storage terminal, MPLX said Wednesday.

The facility, which will be known as MPLX's Mt Airy Terminal, currently has 4 million barrels of leased storage capacity and a 120,000 b/d dock. Space exists to expand storage to 10 million barrels and add a second 120,000 b/d dock.

"This growth potential is significant, as multiple pipelines and rail lines cross the property, and the terminal is positioned as an aggregation point for liquids growth in the region for both ocean-going vessels and inland barges," MPLX said in a statement.

The terminal is located on the Mississippi River between New Orleans and Baton Rouge, near nine lower-Mississippi refineries, including Marathon Petroleum's Garyville, Louisiana, refinery.

"With a prime location on the Mississippi River and proximity to over 2 million b/d of refining capacity, this terminal will serve as a platform to meet growing export needs, expand our third-party business, and give MPLX tremendous flexibility to help its customers meet upcoming International Maritime Organization fuel standards," MPLX president Brian Hennigan said.

MPLX bought the facility for $450 million from Pin Oak Holdings.

Marathon recently consummated its merger with fellow refiner, Andeavor, to become the largest US refining company.

Marathon exported 311,000 b/d of refined products in the second quarter, comprised of about 29% gasoline and 67% diesel, with the remaining 4% asphalt.

The Mt Airy terminal is also located near Marathon's Louisiana asphalt terminal.

https://www.spglobal.com/platts/en/market-insights/latest-news/oil/092618-marathon-petroleum-adds-refined-product-export-capacity-with-louisiana-terminal-purchase

Asia will continue to see ample LPG cargoes lifting from the US Gulf Coast in October to meet demand in Indonesia, Taiwan, South Korea, Japan and South Asia, even as Chinese imports are restricted by higher tariffs on US supply, traders said this week.

Trade sources estimate at least 1.8 million mt will be loaded in October, with only two cargo cancellations heard, as the arbitrage from the US to Asia is wide open.

Sources said Vitol canceled an October 6-7 loading, or October 16-17 cargo, and South Korean trader E1 Corp was heard to have canceled an October 14-15 loading cargo. These could not be immediately confirmed.

Similarly, only one or two September-loading cancellations were heard, which means big volumes will arrive in Asia in October, sources said.

"The East will have enough cargoes from the US," one Western trader said.

About 824,000 mt of LPG had departed from the US for Asia as of September 21, according to data from cFlow, S&p Global Platts trade flow software.

In contrast, there was talk of as many as 10 May-loading cancellations, and seven to 10 cargo cancellations in March, when the arbitrage was crunched by persistently soft Asian prices at the time.

The Western trader said this time, the "arbitrage is open based on low terminal fees" in the US.

The FOB USGC propane cargo premium to cavern product for 44,000-mt shipments loading 30-45 days forward is currently at 5.75 cents/gal -- higher than around 4 cents/gal in mid-August -- but below a peak of 7.25 cents/gal in mid-July.

The terminal fees have fallen due to the closed arbitrage in August when Chinese firms resold US propane at lower levels in Asia ahead of higher tariffs in an escalating trade war.

But as Chinese appetite for alternative cargoes from the Middle East and Africa grows, the price of non-US tons carry a premium to US cargoes. This in effect prompted demand from other Asian buyers for US supply, traders said.

Chinese firms had been swapping US-origin cargoes for those not of US-origin, paying a premium of $5-$10/mt in the process, sources said.

This also helped to support overall regional prices and "the arb is open to Asia," an Asian trader said.

In the Mont Belvieu, Texas, caverns, September non-LST propane prices have weakened relative to crude futures, from 65% of NYMEX WTI in the first half of the month to 61%.

On Wednesday, US Energy Information Administration data showed propane inventories rose 1.6 million barrels to 76.4 million in the week ended September 21, as production rates dipped 40,000 b/d to 1.98 million b/d while exports rose 19,000 b/d to a one-month high of 994,000 b/d.

The Asian physical market has recently been seeing as many 18 bids each day, as buyers noted the number of US cargoes arriving in October and November. Healthy demand from buyers, along with the crude price rally, helped to support the Asian market.

On Tuesday, CFR Japan propane physical prices for front-month H2 October delivery jumped to $670.5/mt -- the highest since November 12, 2014 -- before easing to $664/mt Wednesday, Platts data showed.

In the Asian physical market over the past two weeks, non-US propane tons have been discussed around $7/mt above cargoes that had not been marked as of non-US origin.

Platts calculates the US-Asia arbitrage is currently open around $7/mt. This takes into account the FOB USGC assessment for cargoes loading late October, a $77/mt freight rate and the CFR Japan propane price for the third half-month cycle of H2 November, which on Tuesday was assessed at $667.50/mt, the highest for a third half-month cycle since November 12, 2014, Platts data showed.

ACTIVE FLOWS PUSH FREIGHT TO TWO-YEAR HIGHS

Trade and shipping sources said the busy US export market, activity on the India route and the surge in Chinese demand for Middle East LPG have led to fewer vessels being available for the Persian Gulf-Japan route, propelling VLGC rates to $47/mt, the highest in two years and seven months, Platts data showed.

Freight rates on the Houston-Chiba route climbed to $77/mt and Houston- Flushing to $45/mt, both two-year highs.

The stronger freight is also due to more voyages with fewer cancellations, lots of long-haul voyages, and ships going East via the Cape of Good Hope to Indonesia and South Asia, sources said.

Shipping sources said that with high bunker prices, ships do not need to go full speed unless they have a laycan to reach.

"There are a few more ships available ex-USG for October, but for sure less than what we have seen in a long time. The arbitrage is still positive from the US and with still-uncovered October stems, there could be some more activity," one source said. "November has also started to trade ex-US now."

"Seems most October [loading] cargoes will head East since this seems like the most profitable trade. I still have a feeling that some of these cargoes are heading into China CFR basis and perhaps some of the AG-China cargoes are sold or swapped with importers and traders," the source said.

https://www.spglobal.com/platts/en/market-insights/topics/president-xi-s-second-term

Reuters reported on Wednesday that Nexen Petroleum, a unit of state-controlled CNOOC, was planning to exit the United States, divesting its stake in giant oil and gas developments in the Gulf of Mexico amid the trade row between Washington and Beijing.

People familiar with the matter, speaking on condition of anonymity because it was private, told Reuters on Wednesday Nexen had not determined whether to sell the assets outright or swap offshore acreage with another company.

The decision to sell some U.S. assets in the Gulf of Mexico came as the state-controlled Chinese oil firm finalizes an internal restructuring that combines its Beijing-headquartered exploration and production team with Calgary-based Nexen Petroleum, which it acquired in 2013.

It also follows a large oil discovery at the Stabroek block offshore Guyana, in which CNOOC is partner of a consortium led by Exxon Mobil Corp (XOM.N), and which could recover more than 4 billion barrels of oil.

“We just had a review of the company’s growing global assets... The Guyana discovery is redefining our perspective,” said the spokeswoman.

The state oil firm, however, has no plan to divest stakes in producing oil assets in the Gulf of Mexico, which includes a 25 percent interest in Hess Corp’s (HES.N) Stampede development and a 21 percent stake in Royal Dutch Shell’s (RDSa.L) Appomattox development, the spokeswoman said.

China says U.S. putting 'knife to its neck' on trade

The CNOOC spokeswoman did not comment on a potential link between the firm’s decision to sell some U.S. assets and the Sino-American trade war, but said the strains for a state-owned Chinese company investing in the U.S. partly prompted the firm to consider scaling back.

https://www.reuters.com/article/us-cnooc-oil-usa-nexen/chinas-cnooc-may-divest-some-u-s-assets-after-portfolio-review-idUSKCN1M70OM

BASF, LetterOne sign deal to merge Wintershall, DEA

27 September 2018 22:13 Source:ICIS News

HOUSTON (ICIS)--BASF and LetterOne have signed an agreement to merge their oil-and-gas businesses to create a joint venture called Wintershall DEA, BASF and LetterOne said on Thursday.

The deal should close in the first half of 2019, pending approval of merger control, regulators and the German Federal Network Agency, BASF said.

Wintershall is the exploration-and-production business of BASF. DEA Group is owned by LetterOne, an investment vehicle of Russian magnate Mikhail Fridman.

The table below shows the 2017 financial performance of the combined Wintershall and DEA.

The joint venture plans to reach daily production of 750,000-800,000 bbl/day of oil equivalents by 2021-2023, BASF said. It plans to achieve synergies of at least €200m/year three years after the deal closes.

Wintershall CEO Mario Mehren will become the chairman of the management board and the CEO of the joint venture, BASF said. Maria Moraeus Hanssen, CEO of DEA, will become the deputy CEO and chief operating officer.

A chief financial officer still needs to be chosen, BASF said.

BASF will initially hold a 67% stake in the joint venture, with LetterOne holding the rest, BASF said.

The chemical company will also receive additional preference shares to take into account the value of Wintershall's gas-transportation business, BASF said. These will be converted into ordinary shares no later than 36 months after the deal closes, if not before the initial public offering (IPO) of the joint venture. At that point, BASF's stake in Wintershall DEA will rise to 72.7%.

Brazil’s state-run oil company Petróleo Brasileiro SA said on Thursday in a securities filing it has reached an agreement with U.S. officials to settle investigations in the United States.Photo

Petrobras, as the company is known, will provision $853.2 million in its third-quarter results to pay for the deal with the Department of Justice and the Securities and Exchange Commission.

https://www.reuters.com/article/us-petrobras-lawsuit/petrobras-reaches-deal-with-u-s-officials-in-car-wash-probe-idUSKCN1M71J1

India’s Petronet LNG, the country’s largest importer of liquefied natural gas, is reportedly looking to purchase 9 cargoes of the chilled fuel for delivery in 2019.

The LNG importing company is looking for the cargoes on a cost-and-freight (CFR) or delivered ex-ship (DES) basis to be unloaded at Dahej, Gujarat or Kochi, and Kerala, Reuters reported on Thursday citing a company document.

The cargoes are to be delivered in January, February, April, June, July, August, October, November and December, the report said.

Offers were are due by Thursday.

https://www.lngworldnews.com/report-indias-petronet-lng-seeks-to-buy-9-cargoes/

The Trump administration on Thursday eased safety rules on offshore oil and gas production put in place after the deadly 2010 BP Plc Deepwater Horizon disaster, as part of its effort to slash regulations and boost the energy industry.

The Interior Department revised the 2016 oil and gas production safety systems rule, part of a series of regulations the Obama administration enacted on offshore drilling and production after the drilling well disaster that killed 11 oil rig workers, led to the worst environmental disaster in U.S. history and cost BP about $65 billion.

The final rule will appear in the federal register as soon as Friday, according to a document seen by Reuters.

It eliminates or changes some safety standards for when a well is producing oil or gas, such as requiring that independent third parties certify devices. Other changes involve when operators have to notify the government about beginning oil and gas production and what they have to report about equipment failures.

The Interior Department said in the rule that “certain provisions in that (2016) rulemaking created potentially unduly burdensome requirements for oil and natural gas production operators on the Outer Continental Shelf, without meaningfully increasing safety of the workers or protection of the environment.”

The rule supports the administration’s “objective of facilitating energy dominance” it said.

The move was praised by industry but decried by environmentalists.

“We have a rule that is not a safety rollback, but instead incorporates modern technological advances,” Randall Luthi, president of the National Ocean Industries Association, said on Thursday.

Athan Manuel, director of lands protection at the Sierra Club, said the revisions were an “example of this administration’s shameless attempts to please corporate polluters, no matter the cost to workers’ safety, our health, or the environment.”

https://www.reuters.com/article/us-usa-offshore-oil/u-s-interior-dept-relaxes-rules-on-offshore-oil-gas-production-idUSKCN1M72TU

U.S. company Noble Energy and Israel’s Delek have agreed to acquire a stake in the East Mediterranean Gas company securing ownership in a gas pipeline linking Israel and Egypt, which will serve as a transport route for gas from the Tamar and Leviathan offshore fields.

Namely, EMG is a private company registered in Egypt which owns a 26 inch, c. 90 km subsea pipeline – the EMG Pipeline – connecting the Israeli transmission system in the Ashkelon area with the Egyptian transmission system in the El-Arish area, as well as related facilities.

The EMG Pipeline was designed for a capacity of approx. 7 BCM per year, with an option to increase the capacity to approximately 9 BCM per year by installing additional systems.

The flow of gas through the EMG Pipeline from Egypt to Israel was stopped several years ago, and according to Delek, EMG has no commercial activity.

According to a document shared by Delek, the transaction includes a sale of a 39 percent stake in the pipeline to a joint venture company formed by Delek, Noble, and EGAS for a total amount of $518 million.

Of the $518 million to be paid, Delek and Noble will each pay around $185 million with the balance being paid by the Egyptian Partner.

Gas to flow in 2019

Gas from Israel is expected to start flowing to Egypt through the EMG pipeline at the beginning of 2019.

Initial gas delivery through the EMG Pipeline is expected to occur from the Tamar field to Dolphinus Holdings Limited in Egypt, under Noble Energy’s existing interruptible natural gas sales agreement. At startup of the Leviathan field by the end of 2019, Noble Energy anticipates selling at least 350 million cubic feet of natural gas per day, gross, to contracted customers in Egypt.

J. Keith Elliott, Noble Energy’s Senior Vice President, Offshore, stated, “Today’s announcements mark significant steps forward in supplying natural gas from the world-class Tamar and Leviathan fields to regional customers through existing infrastructure.

“They also represent another major milestone toward Egypt’s goal to become a regional energy hub, providing access to both growing domestic markets and existing LNG export facilities.  With these agreements, we are securing the capacity to deliver on our firm gas sales agreement with Dolphinus for Leviathan while also allowing for interruptible sales from Tamar into Egypt.  This further solidifies the strong cash flow growth anticipated from our Eastern Mediterranean assets.”

Sharing more details on the pipeline transaction, Noble Energy said it would own an effective, indirect interest in the pipeline of approximately 10 percent.  In addition, and upon closing of the transaction, Noble Energy and partners will enter into an agreement to operate the pipeline, securing access to the pipeline’s full capacity.

Technical evaluation and flow reversal planning work on the EMG Pipeline is ongoing.  Key conditions required prior to closing the agreements include gaining necessary regulatory and government approvals, obtaining technical third-party recertification of the EMG Pipeline, completing final transaction due diligence, and confirming sustained gas flow.

Noble Energy also secured an option for an additional route and capacity to transport natural gas within Egypt by entering into a definitive transportation agreement with the owner and operator of the Aqaba El Arish Pipeline.  This agreement will support the transportation of additional quantities of natural gas to Egypt over and above the amounts through the EMG Pipeline, Noble said.

https://www.offshoreenergytoday.com/noble-delek-buy-stake-in-gas-pipeline-between-israel-and-egypt/

Argentina's government wants construction of the country's first LNG liquefaction terminal to start in the second half of 2019, making it possible to export an increasing surplus of production from the giant Vaca Muerta shale play, an official said Thursday.

"We are confident that the decision to push the button on this project will come after the next presidential election in October 2019," Daniel Dreizzen, the country's secretary of energy planning, said at a Moody's finance seminar in Buenos Aires.

He said companies have brought forward proposals for building the terminal, which will be evaluated.

Earlier this month, the country's biggest gas transporter, Transportadora de Gas del Sur (TGS), and Texas-based Excelerate Energy, which operates two floating LNG import terminals in Argentina, agreed to study the possibility of a liquefaction project in Buenos Aires province. They said they would present the proposal to the government by the end of this year for evaluation.

But if no company is ready to advance by next year, Dreizzen said the government will hold an auction to find a builder and operator of the project.

The terminal will have six trains for exporting supplies and should start operations by 2023, with the capacity to ship an initial 40 million cu m/d from Vaca Muerta, Dreizzen told S&P Global Platts on the sidelines of the event.

The likely spot for the terminal will be in Bahia Blanca, a deep-water port in southern Buenos Aires province, where it will be fed with gas from Vaca Muerta in the southwestern Neuquen Basin, he added.

The gas for export will be delivered over a dedicated pipeline under a contract that guarantees it can't be redirected to meet domestic demand, providing more confidence about the supply stability for the project's investors, Dreizzen said.

In the mid- to late 2000s, Argentina reneged on its gas export contracts with Brazil, Chile and Uruguay to meet domestic demand as dwindling production led to shortages.

Now with the incipient development of Vaca Muerta, one of the world's largest shale plays, shortages are becoming a thing of the past, Dreizzen said.

Indeed, his department forecasts that Vaca Muerta will lead a tripling of the country's total gas output to 400 million cu m/d in 2030 from 132 million cu m/d this year, well above the current average demand of 140 million cu m/d.

This will allow gas exports to reach 180 million cu m/d in 2025, with 60 million going to Brazil and Chile and the remaining 120 million to the global market as LNG, according to the forecast.

The growth in production will also make it possible to phase out LNG imports, which were at around 13.1 million cu m/d in 2017, by 2023 and then those from Bolivia by 2026, which averaged 18.8 million cu m/d in 2017, according to Energy Secretariat data.

"We have a unique opportunity," Dreizzen said. "We are becoming a country that will provide energy to the world."

https://www.spglobal.com/platts/en/market-insights/latest-news/natural-gas/092818-argentina-aims-to-start-construction-of-first-lng-export-terminal-in-2019