Magic of Shale: EXPORTS!! Crude Exporters Navigate Gulf Coast Terminal Constraints

[ceo_energemsier + 1,818]

Crude Exporters Navigate Gulf Coast Terminal Constraints

 

U.S. crude exports out of the Gulf Coast averaged more than 2.4 MMb/d in the first four months of 2019 — using infrastructure that is increasingly constrained by a lack of deepwater ports. U.S. crude is reaching destinations worldwide, with large volumes traveling long distances to Asia on gargantuan 2-MMbbl vessels — Very Large Crude Carriers (VLCCs) — loaded offshore by ship-to-ship transfer. Shipments to Europe are primarily on smaller Suezmax and Aframax vessels. Overall, the increased marine activity is testing the limits of existing infrastructure. the past 16 months of crude export vessel movements and their impacts on Gulf Coast ports.

the development of U.S. crude exports since the ban on most overseas shipments was lifted in December 2015. Exports from the Gulf Coast are growing and expected to increase further as new pipelines from the Permian and Eagle Ford come online over the next two and a half. In the less than four years since wide-open exporting began, the rapidly developing export market has overcome a number of challenges, like poor price transparency and the lack of deepwater terminals to load exports Actual shipments still require considerable logistical juggling as crude is loaded from smaller tankers onto long-distance VLCCs for voyages to Asia. ports like the Houston Ship Channel are contending with increased congestion and the resulting difficulties in scheduling. Plans to expand the onshore ports — and build new deepwater terminals offshore — are in the works, but funding and executing on these projects is not easy and can take many years.

 

We reviewed every export shipment from Gulf Coast ports between January 1, 2018 and April 24, 2019, including the size of vessel, load terminal and ultimate destination as well as ship-to-ship transfers onto larger tankers. We’ll begin our discussion of what we learned with a closer look at port activity, then break down the characteristics of crude ship movements affecting marine traffic in the Gulf.

 

 

 

Size Matters

 

With the exception of the Louisiana Offshore Oil Port (LOOP) terminal 20 miles off the Louisiana coast in the Gulf of Mexico, the Gulf Coast is not blessed with deepwater ports that can accommodate massive VLCCs. These supertankers and a handful of their giant brethren — the 3-MMbbl Ultra Large Crude Carriers (ULCCs) — require at least a 75-feet of draft to load fully and are the workhorses of long-distance oil transport between continents. Most Gulf Coast terminals are restricted to a 45-foot draft that only allows them to fully load Aframax tankers holding 500-650 MBbl of crude or to partially load Suezmax tankers that hold up to 1.3 MMbbl. Analysis of the  data shows that during the 16-month period from January 2018 to April 2019, 548 different vessels made a total of 1,402 crude export shipments from Gulf Coast terminals. Of these shipments, 69% involved Aframax tankers, 21% Suezmax, and 6% smaller Panamax (less than 500 Mbbl); 3% were loaded directly onto VLCCs. (As we’ll get to in a bit, many of the smaller tanker loadings were for ship-to-ship transfers to VLCCs.)

 

Load Terminals

  

Figure 1 lists the top 15 export terminals by throughput volume over the analysis period. Enterprise Products Partners’ Enterprise Hydrocarbons Terminal (EHT) in the Houston Ship Channel (HSC) is the Gulf Coast’s busiest crude export terminal, followed by Energy Transfer’s Nederland terminal in Port Arthur, TX, and Moda Midstream’s Ingleside Corpus Christi terminal in third place.

 

 

 

In addition to its terminal on the HSC, Enterprise also operates the fifth and sixth busiest Houston-area terminals: Seaway Texas City and Seaway Freeport. Other top 15 terminals in the Houston region include SemGroup’s Houston Fuel Oil Terminal and the Magellan/LBC Seabrook terminal.

The second busiest crude oil export terminal on the Gulf Coast is Energy Transfer’s Nederland facility, which has 27 MMbbl of storage capacity and pipeline connections from Cushing (TC Energy’s Cushing Marketlink), the Permian (Energy Transfer’s Permian Express and West Texas Gulf pipelines), Houston (Shell Midstream’s Zydeco pipeline) and North Dakota (the Dakota Access Pipeline and the Energy Transfer Crude Oil Pipeline, better known as ETCOP). Nederland has five tanker berths that can fully load Aframax vessels with a 40-foot draft and partially load a Suezmax. Energy Transfer Nederland loaded 146 Aframax and 62 Suezmax tankers between January 1, 2018 and April 24, 2019.

 

Third place among Gulf Coast crude export terminals belongs to the Moda Ingleside Energy Center located in the outer harbor of Corpus Christi. Moda purchased the terminal from Occidental in August 2018, and Oxy remains its principal customer. The purpose-built crude export terminal can partially load VLCCs and Suezmax tankers at three deepwater berths. Export capacity is currently being expanded from 300 Mb/d to 750 Mb/d and the channel draft is being deepened to 54 feet to accommodate fully laden Suezmax tankers. Moda Ingleside receives crude from the Permian and South Texas Eagle Ford basins. The terminal loaded 83 Aframax, 33 Suezmax and 22 partially loaded VLCC tankers between January 1, 2018 and April 24, 2019.

 

During the 16-month period of our analysis, 38% of export shipments were from the Houston region — encompassing the HSC, Texas City, Freeport and Seabrook terminals. The Beaumont/Port Arthur region was second busiest, with 26% of export volumes leaving three facilities: Energy Transfer’s Nederland terminal (mentioned above) and Phillips 66 and Enterprise terminals in Beaumont. Shipments out of Beaumont/Port Arthur just beat volumes leaving the Corpus Christi area (25% of the total), which includes the Buckeye, NuStar and Valero terminals in the Corpus Christi Ship Channel, as well as the Flint Hills Resources (a.k.a. Koch Industries) and Moda terminals at Ingleside. Louisiana accounted for the smallest share of crude export volume leaving the Gulf Coast; the state accounted for 12% of the total. These shipments were made from LOOP in the Gulf of Mexico , the NuStar and Plains terminals in St. James, LA, as well as a few refinery terminals along the Mississippi

 

 

Despite the preponderance of exports loading onto Aframax tankers, most long-distance crude shipments from the Gulf Coast to buyers in Asia are made on VLCCs, because these supertankers boast the most competitive freight rates (see Rock The Boat). Since the direct loading of VLCCs can only happen at deepwater ports like LOOP, it’s common practice to use Aframax and Suezmax tankers to make ship-to-ship transfers (STSs) onto VLCC tankers located in offshore Gulf of Mexico loading zones. These STSs, also known as reverse lightering, allow shippers to load a full VLCC cargo for onward shipment from the Gulf. Our data shows that just under half (or 46%) of the crude export vessels loaded at Gulf Coast ports were for ship-to-ship transfers, with crude loaded onto the smaller tankers at port subsequently loaded onto VLCCs. The data further shows that 85% of Aframax and 76% of Suezmax STS transfers were made onto VLCCs destined for Asia (bottom chart in Figure 2). While VLCCs are popular for the longer-haul Asia runs, smaller Aframax and Suezmax vessels are most popular for shipments to Europe (top chart in Figure 2). During the 16-month analysis period, a total of 306 Aframax and 85 Suezmax tankers were loaded directly (without transfers) for voyages to Europe.

The detailed logistics involved in getting U.S. crude out of Gulf Coast terminals and on their way to export markets underlines the ingenuity of shippers that have built export volumes from next to nothing to more than 2.4 MMb/d in just four years. The upcoming tsunami of crude from new pipelines out of the Permian and Eagle Ford over the next two years will surely test the export infrastructure. That’s the reason behind a slew of new project proposals to build deepwater Gulf of Mexico terminals off the coast of Freeport (TX), Texas City (TX), Corpus Christi, Brownsville (TX) and Louisiana, as well as plans to expand part of the Corpus Christi harbor channel to accommodate fully loaded. If one or more of the new deepwater terminals are built, they would reduce the number of ship-to-ship transfers needed to load export cargoes. Then, in theory at least, pipelines could seamlessly feed deepwater terminals and load VLCC tankers directly and efficiently. If for any reason those deeper terminals don’t get built, expect to see increased congestion as existing Gulf Coast docks struggle to handle ever-larger crude export volumes.

 

 

 

 

 

[ceo_energemsier + 1,818]

Carlyle in talks with pipeline firms to sell 25% stake in U.S. oil export project: source

Carlyle Group LP is in discussions with three companies that operate pipelines and terminals to sell a 25% stake in its Corpus Christi, Texas, crude oil export terminal for $625 million, according to a source familiar with the matter.

Carlyle is also in talks with the three companies to jointly operate a crude oil pipeline from Houston to Corpus Christi, the source said. The identities of the companies could not be immediately learned.

Carlyle and other companies are working to open at least eight facilities to export U.S. crude oil to global markets from the U.S. Gulf Coast. The United States is now producing more than 12 million barrels per day (bpd), more than Saudi Arabia and Russia. Last week, U.S. crude exports were near a new record at nearly 3.4 million bpd.

A deal with one of the three companies, which operate facilities in Houston, could happen as early as Friday, according to the source.

 

The joint-venture pipeline would carry crude from Houston to Corpus Christi with an estimated capacity of between 700,000 to 1.2 million barrels per day (bpd), the source said.

 

It would provide alternate access to U.S. oil producers. Carlyle’s facility has existing connections to producers in the Eagle Ford and the Permian Basin, two of the largest U.S. oil fields.

Carlyle-backed Lone Star Ports LLC is proposing a 1.4 million bpd export facility on a harbor island near Corpus Christi. It has said it expects to begin operations at the facility in October 2020.

Lone Star Ports and its partner, the Port of Corpus Christi, have filed for permits to build a deepwater port that could handle tankers carrying up to 2 million barrels of oil.

 

_______________________________________________________________

 

Carlyle Firm To Seek Fast-Track Approval Of Texas Oil Export Terminal

https://oilprice.com/Latest-Energy-News/World-News/Carlyle-Firm-To-Seek-Fast-Track-Approval-Of-Texas-Oil-Export-Terminal.html#join-discussion

[ceo_energemsier + 1,818]

Typical Worker’s Pay Nears $200,000 at Oil Refiner

 

Workers at oil and gas companies ranked near the top in median pay, as shale boom squeezed already tight labor market.

It was a fruitful year for the rank and file at oil-and-gas companies, from Exxon Mobil Corp. to Phillips 66.

Oil and gas drillers and refiners had some of the highest-paid median workers in the energy and utility sectors in 2018, according to The Wall Street Journal analysis of annual pay disclosures by hundreds of big U.S. companies.

Houston-based Phillips 66 paid its median worker $196,407, the highest of any company in the sector. Phillips was followed by Anadarko Petroleum Corp. at $183,445. Oil giant Exxon Mobil, which has roughly 72,600 employees, according to its latest proxy, had the third-highest median worker pay with $171,375.

Phillips 66 and Anadarko both boosted their 2018 median pay by about 15% in 2018 compared with 2017. Exxon raised its median pay about 6%. Oil-and-gas companies typically pay their workers better than many other sectors because they have fewer low-paid retail jobs and must compete in a tight labor market driven in part by the shale-oil boom.

Phillips 66 and Exxon declined to comment beyond their proxy statements. Anadarko Petroleum didn’t respond to requests for comment.

Utility companies, such as Xcel Energy Inc. and American Electric Power Co., were closer to the energy and utility sector’s median of about $117,000, the highest median of any sector in the S&P 500. An American Electric Power spokeswoman said its compensation plan takes into account employee performance and that the company compares its pay levels to its peers. Xcel Energy didn’t respond to requests for comment.

The lowest-paid median employee in the energy sector worked at Marathon Petroleum Corp., earning $27,703. Unlike other oil and gas producers, Marathon operates roughly 3,900 Speedway convenience stores with about 40,000 employees, most of whom are part-time and work lower-wage jobs, according to Marathon’s latest proxy filing.

Without Speedway, Marathon’s median worker pay is $167,607, according to its proxy filing. The company claims in its filing that it is the only domestic downstream refining company with a substantial retail presence.

[James Regan + 1,776]

9 hours ago, ceo_energemsier said:

Crude Exporters Navigate Gulf Coast Terminal Constraints

 

U.S. crude exports out of the Gulf Coast averaged more than 2.4 MMb/d in the first four months of 2019 — using infrastructure that is increasingly constrained by a lack of deepwater ports. U.S. crude is reaching destinations worldwide, with large volumes traveling long distances to Asia on gargantuan 2-MMbbl vessels — Very Large Crude Carriers (VLCCs) — loaded offshore by ship-to-ship transfer. Shipments to Europe are primarily on smaller Suezmax and Aframax vessels. Overall, the increased marine activity is testing the limits of existing infrastructure. the past 16 months of crude export vessel movements and their impacts on Gulf Coast ports.

 

the development of U.S. crude exports since the ban on most overseas shipments was lifted in December 2015. Exports from the Gulf Coast are growing and expected to increase further as new pipelines from the Permian and Eagle Ford come online over the next two and a half. In the less than four years since wide-open exporting began, the rapidly developing export market has overcome a number of challenges, like poor price transparency and the lack of deepwater terminals to load exports Actual shipments still require considerable logistical juggling as crude is loaded from smaller tankers onto long-distance VLCCs for voyages to Asia. ports like the Houston Ship Channel are contending with increased congestion and the resulting difficulties in scheduling. Plans to expand the onshore ports — and build new deepwater terminals offshore — are in the works, but funding and executing on these projects is not easy and can take many years.

 

 

 

We reviewed every export shipment from Gulf Coast ports between January 1, 2018 and April 24, 2019, including the size of vessel, load terminal and ultimate destination as well as ship-to-ship transfers onto larger tankers. We’ll begin our discussion of what we learned with a closer look at port activity, then break down the characteristics of crude ship movements affecting marine traffic in the Gulf.

 

 

 

 

 

 

 

Size Matters

 

 

 

With the exception of the Louisiana Offshore Oil Port (LOOP) terminal 20 miles off the Louisiana coast in the Gulf of Mexico, the Gulf Coast is not blessed with deepwater ports that can accommodate massive VLCCs. These supertankers and a handful of their giant brethren — the 3-MMbbl Ultra Large Crude Carriers (ULCCs) — require at least a 75-feet of draft to load fully and are the workhorses of long-distance oil transport between continents. Most Gulf Coast terminals are restricted to a 45-foot draft that only allows them to fully load Aframax tankers holding 500-650 MBbl of crude or to partially load Suezmax tankers that hold up to 1.3 MMbbl. Analysis of the  data shows that during the 16-month period from January 2018 to April 2019, 548 different vessels made a total of 1,402 crude export shipments from Gulf Coast terminals. Of these shipments, 69% involved Aframax tankers, 21% Suezmax, and 6% smaller Panamax (less than 500 Mbbl); 3% were loaded directly onto VLCCs. (As we’ll get to in a bit, many of the smaller tanker loadings were for ship-to-ship transfers to VLCCs.)

 

 

 

Load Terminals

 

 

  

Figure 1 lists the top 15 export terminals by throughput volume over the analysis period. Enterprise Products Partners’ Enterprise Hydrocarbons Terminal (EHT) in the Houston Ship Channel (HSC) is the Gulf Coast’s busiest crude export terminal, followed by Energy Transfer’s Nederland terminal in Port Arthur, TX, and Moda Midstream’s Ingleside Corpus Christi terminal in third place.

 

 

 

 

In addition to its terminal on the HSC, Enterprise also operates the fifth and sixth busiest Houston-area terminals: Seaway Texas City and Seaway Freeport. Other top 15 terminals in the Houston region include SemGroup’s Houston Fuel Oil Terminal and the Magellan/LBC Seabrook terminal.

 

The second busiest crude oil export terminal on the Gulf Coast is Energy Transfer’s Nederland facility, which has 27 MMbbl of storage capacity and pipeline connections from Cushing (TC Energy’s Cushing Marketlink), the Permian (Energy Transfer’s Permian Express and West Texas Gulf pipelines), Houston (Shell Midstream’s Zydeco pipeline) and North Dakota (the Dakota Access Pipeline and the Energy Transfer Crude Oil Pipeline, better known as ETCOP). Nederland has five tanker berths that can fully load Aframax vessels with a 40-foot draft and partially load a Suezmax. Energy Transfer Nederland loaded 146 Aframax and 62 Suezmax tankers between January 1, 2018 and April 24, 2019.

 

 

 

Third place among Gulf Coast crude export terminals belongs to the Moda Ingleside Energy Center located in the outer harbor of Corpus Christi. Moda purchased the terminal from Occidental in August 2018, and Oxy remains its principal customer. The purpose-built crude export terminal can partially load VLCCs and Suezmax tankers at three deepwater berths. Export capacity is currently being expanded from 300 Mb/d to 750 Mb/d and the channel draft is being deepened to 54 feet to accommodate fully laden Suezmax tankers. Moda Ingleside receives crude from the Permian and South Texas Eagle Ford basins. The terminal loaded 83 Aframax, 33 Suezmax and 22 partially loaded VLCC tankers between January 1, 2018 and April 24, 2019.

 

 

 

During the 16-month period of our analysis, 38% of export shipments were from the Houston region — encompassing the HSC, Texas City, Freeport and Seabrook terminals. The Beaumont/Port Arthur region was second busiest, with 26% of export volumes leaving three facilities: Energy Transfer’s Nederland terminal (mentioned above) and Phillips 66 and Enterprise terminals in Beaumont. Shipments out of Beaumont/Port Arthur just beat volumes leaving the Corpus Christi area (25% of the total), which includes the Buckeye, NuStar and Valero terminals in the Corpus Christi Ship Channel, as well as the Flint Hills Resources (a.k.a. Koch Industries) and Moda terminals at Ingleside. Louisiana accounted for the smallest share of crude export volume leaving the Gulf Coast; the state accounted for 12% of the total. These shipments were made from LOOP in the Gulf of Mexico , the NuStar and Plains terminals in St. James, LA, as well as a few refinery terminals along the Mississippi

 

 

Despite the preponderance of exports loading onto Aframax tankers, most long-distance crude shipments from the Gulf Coast to buyers in Asia are made on VLCCs, because these supertankers boast the most competitive freight rates (see Rock The Boat). Since the direct loading of VLCCs can only happen at deepwater ports like LOOP, it’s common practice to use Aframax and Suezmax tankers to make ship-to-ship transfers (STSs) onto VLCC tankers located in offshore Gulf of Mexico loading zones. These STSs, also known as reverse lightering, allow shippers to load a full VLCC cargo for onward shipment from the Gulf. Our data shows that just under half (or 46%) of the crude export vessels loaded at Gulf Coast ports were for ship-to-ship transfers, with crude loaded onto the smaller tankers at port subsequently loaded onto VLCCs. The data further shows that 85% of Aframax and 76% of Suezmax STS transfers were made onto VLCCs destined for Asia (bottom chart in Figure 2). While VLCCs are popular for the longer-haul Asia runs, smaller Aframax and Suezmax vessels are most popular for shipments to Europe (top chart in Figure 2). During the 16-month analysis period, a total of 306 Aframax and 85 Suezmax tankers were loaded directly (without transfers) for voyages to Europe.

 

The detailed logistics involved in getting U.S. crude out of Gulf Coast terminals and on their way to export markets underlines the ingenuity of shippers that have built export volumes from next to nothing to more than 2.4 MMb/d in just four years. The upcoming tsunami of crude from new pipelines out of the Permian and Eagle Ford over the next two years will surely test the export infrastructure. That’s the reason behind a slew of new project proposals to build deepwater Gulf of Mexico terminals off the coast of Freeport (TX), Texas City (TX), Corpus Christi, Brownsville (TX) and Louisiana, as well as plans to expand part of the Corpus Christi harbor channel to accommodate fully loaded. If one or more of the new deepwater terminals are built, they would reduce the number of ship-to-ship transfers needed to load export cargoes. Then, in theory at least, pipelines could seamlessly feed deepwater terminals and load VLCC tankers directly and efficiently. If for any reason those deeper terminals don’t get built, expect to see increased congestion as existing Gulf Coast docks struggle to handle ever-larger crude export volumes.

 

 

 

 

 

 

 

 

That’s a lot of crude being bunkered. I’m no Greenie but all it will take is one Exxon Valdez incident and the show will begin. The USA is undoubtedly proving itself as a mega net exporter and in a very short space of time. This has the ingredients for a green onslaught god forbid!!!

[ceo_energemsier + 1,818]

1 minute ago, James Regan said:

That’s a lot of crude being bunkered. I’m no Greenie but all it will take is one Exxon Valdez incident and the show will begin. The USA is undoubtedly proving itself as a mega net exporter and in a very short space of time. This has the ingredients for a green onslaught god forbid!!!

There was a recent incident in Houston...................

https://www.cbsnews.com/news/houston-ship-channel-barges-and-oil-tanker-collide-today-2019-05-10/

https://gcaptain.com/houston-ship-channel-reformate-spill/

[ceo_energemsier + 1,818]

Flexible US LNG contracts driving global spot market growth: API

Buyers faced with unprecedented choice, flexibility

Transforming project financing, market access

Price transparency key to full commoditized market

 

Flexible US LNG contracts are helping to create a global, commoditized spot market and transforming project financing models, according to US oil and gas trade body the American Petroleum Institute.

 

The US could become the world's third largest LNG exporter by the end of this year, after Qatar and Australia, and is bringing "unprecedented" options for pricing and contract terms to the market, API policy officer Dustin Meyer told S&P Global Platts in an interview Monday.

"The beauty of US LNG is that no one really knows how it will be priced, and that's a unique amount of flexibility, of optionality, for potential buyers," he said.

For decades LNG buyers "really only had one option" for pricing -- linking to Brent oil.

The first wave of US LNG export projects, which are coming online now, generally used prices linked to the US Henry Hub.

Developers for the second wave, who are looking to sign contracts now, are being more flexible to attract buyers. There are many options, including hybrid approaches where prices are linked partly to Henry Hub, and partly to a European hub price, such as the Dutch TTF or UK NBP.

"Maybe you can mix in a bit of Brent oil. Maybe you go all Brent oil," Meyer said.

Some developers have even offered a bit of linkage to the West Texan hubs where prices can be very low or even negative because there are no links to the coast yet to enable surplus gas to be exported.

"It's really an unprecedented amount of innovation that ultimately benefits the buyer," he said.

Prices becoming more transparent Meyer sees a trend toward more price transparency in the US as well as Asia and Europe.

"That makes project development a lot easier. It's a sign of the maturing nature of the LNG market, as it moves closer to commoditization," he said.

"The more you get to a spot-based market, the more comfortable financial backers are taking a risk on new export projects, which makes it more likely additional capacity comes online," he said.

New projects still benefit greatly from having long-term contracts to get them to a final investment decision, however.

"If you're a new company and you're only focused on one LNG project in the US, then it's going to be more difficult to get financing unless you have those bankable long-term contracts," he said.

"So you're still going to see long-term contracts being signed, but they could be for 12 or 15 years, as well as for 20," he said.

Long-term contracts do not restrict the rise in spot sales, though, as the cargoes can still be sold on a flexible, spot basis by the original buyer.

"That's what we see happening, because there are no destination clauses attached to US LNG," Meyer said.

Trading houses Trafigura and Gunvor, for example, have been able to enter the market because the increase in flexible US LNG cargoes makes it easier to trade in the spot market.

"There's absolutely no obligation for what you do when you pick up your US LNG cargo, and that's different from how LNG projects used to be developed," he said.

A growing LNG spot market with more transparent prices also benefits new customers who might not have the credit to sign a long-term contract, or build a dedicated import terminal.

It helps lower these barriers to entry, and gives people the freedom to respond to market conditions and add LNG to their portfolios, he said.

Prices not politicians drive flows Meyer was circumspect about the European Commission's hopes that the US could eventually become "the major supplier" to Europe, however.

"There's no direct way that the EU or national governments can cooperate with the US government in a commercial way to require a certain percentage or volume of US LNG to go to Europe," he said.

US LNG flows to Europe have surged in the last two quarters as a narrow price spread with Asian LNG made Europe often the most profitable destination.

By early May this year Europe had imported 4.4 Bcm of LNG from the US, already more than the 4.3 Bcm it imported in the whole of 2018, according to data from S&P Global Platts Analytics.

"Governments can be lauded for not creating any obstacles to that, but flows must be left to commercial decisions based on market conditions," Meyer said.

Europe's US LNG imports are also still tiny compared with its major supplier Russia, which sent 200 Bcm of pipeline gas and 10 Bcm of LNG to Europe in 2018.

By early May Europe had imported 6.6 Bcm of Russian LNG -- more than from the US -- as well as 37 Bcm of pipeline gas, the Platts Analytics data showed.

 

 

[footeab@yahoo.com + 2,192]

6 minutes ago, James Regan said:

That’s a lot of crude being bunkered. I’m no Greenie but all it will take is one Exxon Valdez incident and the show will begin. The USA is undoubtedly proving itself as a mega net exporter and in a very short space of time. This has the ingredients for a green onslaught god forbid!!!

Less oil is moving around the Gulf now than a decade ago.  A LOT less.  Suggest an import/export chart of oil products....

[ceo_energemsier + 1,818]

Advice From George Mitchell: 'Be Bold'

The pioneer of the world's shale plays discusses the future of energy development in this exclusive interview with Hart Energy, celebrating the 30th anniversary of his Barnett play opener.

Nissa Darbonne, Editor-at-Large

Fri, 04/15/2011 - 16:00

 

 

George Mitchell's advice to oil and gas explorationists? "Be bold."

The founder of America's--and now the world's--unconventional oil and gas plays says the late, legendary explorer Michel Halbouty would rib him decades ago, telling him, "Come on. Explore. Do something."

Upon discovering how to extract natural gas resources from the Barnett shale after a first well, C.W. Slay No. 1 in Newark East Field, 30 years ago, and hundreds more thereafter, he told Halbouty, "Mike, I found this field because of you."

He quips in this exclusive interview with Hart Energy for a video tribute that celebrates the 30th anniversary of C.W. Slay, the Barnett play opener, "I've been busy now for 60 years, drilling wells all over the country, and now I've done something important."

(Editor’s Note:The 30th anniversary of America’s shale plays will be celebrated at Hart Energy's sixth annual Developing Unconventional Gas (DUG) conference April 18-20 in Fort Worth with more than 2,000 attendees and a keynote address by President George W. Bush. For conference details and to register, click DUGConference.com.)

The application Mitchell pioneered of horizontal drilling and multi-stage fracturing into the low-permeability, low-porosity shale has re-invented the U.S. natural gas profile. The U.S. led in 2009 for a third consecutive year in percentage increase in gas production, posting 3.5% more than in 2008, according to the annual BP Statistical Review of World Energy published in June 2010.

It has surpassed Russia as the world's most prolific gas producer.

And, the application of the technology into U.S. oil plays now contributed to the U.S. also posting the largest increase in oil production in 2009. "(Daily) U.S. production increased by 460,000 barrels, or 7%--the largest increase in the world last year and the largest U.S. percentage increase in our data set," the BP Plc analysts report. That data set is of 59 years of world production history.

Mitchell says America could readily use the additional oil that is being produced from horizontal and multi-frac plays. "We have to get more oily and you'll see a lot of the industry trying to make more oil out of plays…If we have the same information on oil plays right now that we have on the gas plays, we would solve a lot of our oil problems…There's a lot of work that's still to be done."

According to data from Whiting Petroleum Corp., a leading operator in the Bakken oil play in North Dakota, production there has gone from virtually zero several years ago to some 400,000 barrels per day. Pipeline operators are gearing up to increase take-away capacity from the Williston Basin to nearly 1 million barrels a day by year-end 2013, according to Jim Volker, Whiting chairman and chief executive.

Mitchell says the Bakken is a play he missed, and chuckles. "The Bakken's been an old play. I remember looking at it. I drilled a well there back in '83, a wildcat well. We had the (oil) show, but we never could make a well out of it. I couldn't figure out how I missed it, but I did.

"It's a big play now and it's oil, so that's good for the country."

Some more highlights:

--On the Marcellus shale, Mitchell accumulated 50,000 acres over the Btu-rich gas play in Appalachia, and sold it "for a nice profit." After drilling just the first of several wells, "I began to think half the state (of Pennsylvania) would make gas and, after it's all developed, we'll find out. It’s interesting this is such a large play (involving Pennsylvania and neighboring states)…The Marcellus is a tremendous play."

--On exporting now-abundant U.S. gas, he hopes it isn't. "I don't think they should (export it) right now. I think they should work on how to use more gas (here), like they're doing now and that Boone Pickens is talking about."

Pickens has been lobbying the U.S. government to incent use of natural gas as a transportation fuel, beginning with heavy-duty trucks. One Mcf (thousand cubic feet) of gas is the energy equivalent of five gallons of diesel, Pickens tells OilandGasInvestor.com in the exclusive article "Boone Pickens OK With Exporting U.S. Gas, But Would Be Disappointed" (March 31, 2011).

Mitchell says, "If you have trucks getting three miles to the gallon, get fuel for them. Let's figure out how to do that. I think there are a lot of gas uses that this nation needs and that can be devised from the excess gas that's coming out of the shales…The gas production can help take care of some of our oil needs.

"Oil production is still deficient, but we have excess gas."

--He urges producers to take care of water use when drilling, though. While one of the most recognized American oil and gas explorationists, Mitchell is also active in environmental and ecological endeavors, such as creating The Woodlands, Texas, community north of Houston.

"You have to clean up the water (used in drilling). It is extremely important that the industry is not criticized for not cleaning up the water. Devon (Energy Corp.) is doing a good job. The industry needs to work with the government and help them understand. I think we can do much better."

--Where would Mitchell look for oil today? "I'd still say the shales right now, and I'm looking at that too."

--And, about how major oil companies, both American and foreign, are knocking on relatively small U.S. independents' doors, wanting to know how to work the shales, he says, "It's amazing, what the independents have done. Twenty years ago, everyone thought they'd be out of business."

 

 

_______________________

[ceo_energemsier + 1,818]

Celebrating The Late Shale Pioneer George Mitchell

George Mitchell would have turned 100 years old today. In celebration, we look back at the accomplishments that made him a legend in U.S. oil and gas.

Hart Energy

Tue, 05/21/2019 - 04:30

 

Perhaps no quote encapsulates the overall importance that the late George Mitchell held in the development of U.S. shales and the growth of America’s position in world energy markets than this one.  “George Mitchell dramatically changed America’s energy position,” IHS Markit’s Daniel Yergin told Oil and Gas Investor’s Leslie Haines following the shale pioneer’s death at 94 in 2013.

It was Mitchell’s E&P company, Mitchell Energy & Development Corp., that experimented doggedly for 17 years to create the “overnight success” of the Barnett shale of North Texas. Its eventual success led the oil and gas industry into a leasing and drilling frenzy from roughly 2004 to today as shale plays in other basins were developed.

Today would have been Mitchell’s 100th birthday.

We here at Hart Energy feel this occasion is the perfect time to revisit the legacy of the man who participated in drilling some 10,000 wells, including more than 1,000 wildcats.

He was also a community philanthropist. To combat poverty, and because he was interested in urban planning and preserving the environment, in 1975 he opened one of the most successful mixed-use “New Towns” in the U.S. with The Woodlands, just north of Houston. Rather than a bedroom suburb, he envisioned a full-blown town where people live, work, and play among the trees – all power lines are underground, billboards are prohibited, and trees are preserved in all developments. Today this parklike atmosphere is home to about 120,000 people.

And he spent millions on historic preservation in his home town, Galveston, helping to revive its once-moribund economy and reinstituting Mardi Gras each spring.

In this video presentation titled, “George Mitchell and the Barnett Shale,” that was produced and originally aired as a tribute in his honor, notable industry executives discuss how one man’s unconventional thinking revolutionized an entire industry.

[ceo_energemsier + 1,818]

A Visit with George Mitchell

From shale development and gas demand to sustainability and beefing up the Texas university system’s image, this Renaissance man has a lot on his mind.

By Leslie Haines, Hart Energy

Mon, 11/01/2010 - 00:00

 

Iconic Houston oilman and entrepreneur George P. Mitchell, at 91, is not resting on his laurels. Last December, he dedicated the George P. Mitchell Physics Building at Texas A&M University, his beloved alma mater, following a $52-million donation to create a new physics institute that includes a second building. His goal is to elevate A&M's reputation and compete with Ivy League schools on the East and West coasts.

In June, son Todd went to Amsterdam to accept on his behalf a Lifetime Achievement Award from the Gas Technology Institute, presented during its conference.

"I believe that the United States should examine all forms of natural gas in order to ease our dependence on coal and foreign oil," said Mitchell upon receiving the award. "It is my hope that my efforts will aid the search for new and unconventional energy sources that can be used by my 23 grandchildren and four great-grandchildren."

Founder of Mitchell Energy & Development Corp., Mitchell was recognized for pioneering hydraulic fracturing and drilling technologies in the 1980s in the Fort Worth Basin, home of the Barnett shale. These advances have since enabled the shale-gas revolution that has swept the U.S., and soon, the rest of the world.

This Renaissance man is the perfect embodiment of the American Dream. Born in Galves­ton in 1919 of Greek immigrants, he bused tables to work his way through A&M. Today, perennially on Forbes' list of the wealthiest Americans, he is well known for his philanthropy in the Texas medical community and at A&M; for rejuvenating his hometown, Galves­ton, through historic preservation and economic development; and for his utopian vision in developing The Woodlands, a master-planned new town north of Houston that he began in the early 1970s. Today it is home to more than 92,000 people.

A petroleum engineer with geology training from A&M, class of 1940, Mitchell believed natural gas could be extracted from shale when no one else did. "Not wanting his oil wells to go to waste in the event of flow shortages, Mitchell had his employees drill into an area known as the Barnett shale for hydrocarbons," said the GTI when giving him the award. "Despite the cautioning of his engineers that the endeavor could prove futile, Mitchell gave the order to fracture the rock.

"The company invested in more than 30 wells to test different processes of hydraulic fracturing, with some wells' production barely even covering the cost of operation. Yet Mitchell remained steadfast, continuing to analyze test results that yielded the greatest return, and eventually completed the first successful instance of using hydraulic fracturing to drill into shale for natural gas.

"The results were staggering—many experts believe the Barnett shale may be the largest onshore natural gas field in the United States, containing more than an estimated 26 trillion cubic feet of natural gas."

Devon Energy Corp. acquired Mitchell Energy in 2002 for $3.1 billion, adding horizontal drilling and other innovations to make fracture-stimulated wells produce even more from the Barnett shale. Mitchell is its largest shareholder and Todd represents him on the board. Today, Mitchell's legacy has grown to give Devon some 18 trillion cubic feet equivalent of net risked potential and more than 6,000 drilling locations in this shale alone.

Oil and Gas Investor met with Mitchell in his award-laden office in Houston.

Investor: How do you react when people say you are the father of the shales?

Mitchell: Well, I did so much work on it, now they blame me for it. When I started in the '80s, the price of natural gas was $10 or $11 a thousand—in those days it was price-controlled by the government. Then they decontrolled it and prices fell all the way back to $3.50 or $4, so people blamed me for that. They said we found a big supply of gas. I said, that's too bad, but it's good for the country. Now, 25 years later, the price is still below $4.

More gas demand is going to help lower oil demand too. It'll take over some of the things oil is used for now. There's enough gas in the U.S. for the next 50 or 100 years. We probably have 2 or 3 Tcf of extra gas above demand, so we need to get going on building demand. Four dollars is just about your cost of horizontal drilling, so we've got to build up demand, take away from oil, and see if we can't get the price back up, and help the oil-import situation.

Investor: How do you think we should do that?

Mitchell: There is a lot going on now. I think the Pickens Plan idea to get major trucking companies to use gas is a good idea. The gas supply committees and the Department of Energy ought to be working hard to use these shale-gas supplies wherever we can. Electric power generation with oil is very expensive. You could use more shale gas.

Investor: Ever ride in a natural gas vehicle?

Mitchell: Yes, I have. It works very well. There's no doubt about the technology. We just need refueling places along the super-highways.

Investor: Why were you so persistent about the Barnett shale? Was it a hunch? Did you really need that gas?

Mitchell: It became clear to me that the source of gas in the Fort Worth Basin and through the Bend Arch, and even in the Caddo area, was from the Barnett. It came up through the faults and fractures. You could see it on seismic. You could see it on small gas shows when we'd penetrate the Barnett shale on the way to the Ellenburger.

My geologists who examined the cores told me, "You're wasting your money, Mitchell, trying to make that work. There is no porosity." It took us from about 1989 to 1991 to experiment with several wells and different ways to frac them.

All the people who used to work for me, who told me we couldn't drill the Barnett shale, now they have their own companies drilling for shale. This is a real boom. The companies from Europe, from China, they're all coming over here.

Horizontal drilling has really made a big difference. In the Barnett alone Devon has enough acreage to drill 500 wells a year for 10 years.

Investor: What do you think about Devon exiting the Gulf of Mexico?

Mitchell: Before the blowout, Devon came to the conclusion to get out of the Gulf. They had made a discovery at the Kaskida block, but those are tough wells to drill. You have to drill an appraisal well to get SEC confirmation of the reserves. But what should have been a $100-million well cost much more than that, and it scared the hell out of them. They had 21 good prospects next to BP's blocks so they made a deal with BP. It also included Devon's assets offshore Brazil. I tried to get Devon to keep a 50% interest in those Gulf blocks, and let BP drill them, prove up the reserves. But Devon wants to concentrate on big shale projects. They've got plenty to do.

If this Macondo accident had happened to Devon, their stock probably would have gone to zero. It'd be worthless. You have to be big to withstand that.

BP can survive this, but it has a big fight on its hands, and so does Anadarko. If I was a younger man, I'd get right in the middle of it! It'd be better than being an oil and gas man!

Investor: But seriously, if you were 40 again, which would you rather do: oil and gas, or community development like The Woodlands?

Mitchell: My main background is oil and gas. I am a petroleum engineer and geologist.

Investor: You are interested in many other things besides oil and gas.

Mitchell: One of the most important things I'm still working on is sustainability. I learned about it in the '70s from Buckminster Fuller. He said if you can't make things work for 6 billion people now, how are you going to make them work when we have 9 billion by 2050? How do you make the world work for your grandchildren? All the nations have to realize what's going on and you have to get the young people involved.

Investor: What are your ideas?

Mitchell: You set up programs at all the universities. Stanford has done some action on it; the University of Texas has; Virginia has. But are they really working on it, or is it just a bunch of papers? What made me angry was that none of the Southwest Conference universities were working on sustainability.

Investor: Why so interested in physics?

Mitchell: In 2002, my friend Peter McIntyre, an A&M physicist, took me to California to meet Stephen Hawking (the widely known physicist who wrote A Brief History of Time). I told him I wanted to bring him to A&M and form collaborations between A&M and Cambridge University, where he worked. I wanted to help improve A&M's image, and we are working on joint arrangements. He's coming back to A&M next spring.

Investor: You are still drilling wells?

Mitchell: My son Todd has an E&P company. He bought some Marcellus acreage and drilled a few wells, then sold it and made some good money. Pennsylvania is a real eye-opener. I think half the state is going to be productive.

Investor: What's the best advice you ever got?

Mitchell: My old A&M professor told me if you go to work for a major company, you'll drive a nice Chevrolet, but if you go independent, you might end up with a Cadillac. Just turn loose. That was very good advice.

Investor: And your advice to us today?

Mitchell: If we really clean up the water, we can do the job of producing oil and gas safely. If we don't do the job right, then the environmentalists should give us hell. We can do it.

 

[ceo_energemsier + 1,818]

Our thanks to George Mitchell

He drilled 10,000 wells during his career, but those in the Barnett shale changed everything.

Leslie Haines, Hart Energy

Tue, 09/03/2013 - 00:00

 

He was born in Galveston, Texas, in 1919, the son of Greek immigrants, and he died there in July 2013 at age 94, a billionaire. But through the years in between, oh what a life!

George P. Mitchell has been highly praised since his passing. Tributes have stacked up from oil and gas industry executives who owe so much to the so-called “father of fracing.” Others have mentioned his lifelong love of science, especially of astronomy and physics, and his study of sustainability – the greatest example of which is The Woodlands, Texas, a master-planned community north of Houston that has been emulated by urban planners around the world.

Mitchell could see far and connect the dots. Source after source cites his visionary nature, always looking out 30 years. To him, the environment, sustainable development of oil and gas fields, and real estate communities all fit into one philosophy.

In August 2012 Mitchell and coauthor New York Mayor Michael Bloomberg published an op ed in the Washington Post and other major papers defending the safety and efficacy of hydraulic fracturing. But true to his own environmental activism, at the same time Mitchell urged the industry to adopt and adhere to best practices.

Mitchell and Bloomberg wrote, “Fracing for natural gas can be as good for our environment as it is for our economy and our wallets, but only if done responsibly. The rapid expansion of fracing has invited legitimate concerns about its impact on water, air, and climate – concerns that industry has attempted to gloss over. With so much at stake for the environment, jobs, and energy security, it is critical that we make reasoned decisions about how to manage the use of hydraulic fracturing technology.

“We can frac safely if we frac sensibly. That may not make for a great bumper sticker. It does make for good environmental and economic policy.”

It was Mitchell’s E&P company, Mitchell Energy & Development Corp., that experimented doggedly for 17 years to create the “overnight success” of the Barnett shale of North Texas. Its eventual success led the oil and gas industry into a leasing and drilling frenzy from roughly 2004 to today as shale plays in other basins were developed.

Today the industry is in a tremendous harvest mode, with thousands of wells yet to be drilled in each shale play, and the US economy is benefiting. Domestic oil and gas production has steadily risen since that time. There is serious talk of energy independence, exporting natural gas in the form of LNG, and exporting refined petroleum products.

“George Mitchell dramatically changed America’s energy position,” said Daniel Yergin, vice chairman of IHS CERA and founder of Cambridge Energy Research Associates, upon learning of Mitchell’s passing. In 2012 Yergin and some others had proposed that Mitchell receive the Presidential Medal of Freedom for his contributions to science and the energy industry.

Throughout his career, Mitchell participated in drilling some 10,000 wells, including more than 1,000 wildcats. Mitchell Energy was credited with more than 200 oil and 350 natural gas discoveries. The firm spent nearly two decades developing hydraulic fracturing, finally finding success in North Texas’ Barnett shale formation in the 1990s.

It is not often that one man makes such an indelible mark on an industry or community. It is rare indeed that Mitchell did this in many different spheres, from energy technology to environmentalism to sustainable urban development to astrophysics. He co-funded some of the mirrors on the giant Magellan telescope, for example.

He was known for his keen intellect, graduating from Texas A&M University in 1940 first in his class and captain of the tennis team. Years later, he started and endowed the Houston Advanced Research Center (HARC), aiming to create a “Silicon Valley” hotbed of innovation in Texas. Late in life, he counted the famed physicist Stephen Hawking as a friend. Mitchell wanted Texas A&M to compete with elite universities on both coasts of the US, he said, and he declared he’d make it happen. He donated US $52 million for construction of two buildings for the George P. and Cynthia Woods Mitchell Institute for Fundamental Physics and Astronomy.

Mitchell came from modest roots and sold stationery and candy to get through college, yet he always made philanthropy and education keystones of his life after that, especially after he sold his Fortune 500 company, Mitchell Energy, to Devon Energy Corp. in 2002 for $3.5 billion.

To combat poverty, and because he was interested in urban planning and preserving the environment, in 1975 he opened one of the most successful mixed-use “New Towns” in the US with The Woodlands. Rather than a bedroom suburb, he envisioned a full-blown town where people live, work, and play among the trees – all power lines are underground, billboards are prohibited, and trees are preserved in all developments. Today this parklike atmosphere is home to about 120,000 people.

And he spent millions on historic preservation in his home town, Galveston, helping to revive its once-moribund economy and reinstituting Mardi Gras each spring. Earlier this year he attended the annual ball in costume and face paint, as he always did.

Persistence pays off

But for the oil and gas industry, it is Mitchell’s early work to figure out how to drill and produce the Barnett shale in the Fort Worth basin for which he will be remembered, as fracture technology has ended up being the key to unlocking shale formations around the world.

“There’s no point in mincing words. Some people thought it was stupid,” Dan Steward, a geologist who joined Mitchell Energy in 1981, told The Associated Press in an interview last year.

Steward estimated in the early years, “probably 90% of the people” in the firm didn’t believe shale gas would be profitable and that Mitchell’s company didn’t even cover the cost of fracing on shale tests until the 36th well was drilled. “There’s not a lot of companies that would stay with something this long,” he said. “Most companies would have given up.”

In 1981, Mitchell Energy culminated years of experimentation when it drilled the C.W. Slay No. 1, which became the discovery well for the Newark East (Barnett shale) gas field. It was drilled to about 2,380 m (7,800 ft) in the southeast corner of Wise County, Texas, southeast of the large and established Boonsville (Bend Conglomerate) gas field. Mitchell had been drilling vertical gas wells in this county since the 1950s when he started his company.

“There were many times during its early life that the Barnett play was on the verge of failing, and had it not been for the conviction, commitment, and determination of George P. Mitchell and Mitchell Energy, it would not be what it is today,” wrote Steward in his history, “The Barnett Shale Play: Phoenix of the Fort Worth Basin,” published by the Fort Worth and North Texas geological societies in 2007.

A number of developments contributed to Mitchell’s eventual success. Fracture-stimulation technology was advancing. In 1979 Mitchell performed the nation’s largest hydraulic frac of that era, in Limestone County in East Texas, using gelled water, with 1 MMgal of fluid and 2.8 MMlb of sand. Also, geological thinking kept advancing. He and other geologists had begun to suspect that the Barnett shale underlying the North Texas region was the source rock for the oil that was being produced at the time.

By 1987 Mitchell had drilled 36 wells in the Barnett before it could book commercial reserves, Steward wrote. Starting in 1990 Mitchell and the Gas Research Institute agreed to work together on the Barnett for another 10 years of R&D. With this assistance and funding from the federal government, more wells were drilled. Each time, different frac techniques were tried, and reservoir modeling and mapping were done.

By 1992 Mitchell’s team believed it had 3.6 Bcm/sq km (50 Bcf/sq mile) of gas in place in the Fort Worth basin, so it approached the Texas Railroad Commission to obtain permission for 80-acre spacing in the Newark East field. By 1994 the Barnett had replaced the Bend Conglomerate as the main source of new gas production for Mitchell in North Texas.

Mitchell acquired 1,295 sq km (500 sq miles) of 3-D seismic data in North Texas, and about half of those data were applicable to the Barnett. Foam fracs were changed to light sands fracs; downhole motors were used; other new ideas were tried.

The Devon deal

Through the 1990s, Mitchell’s team continued to expand and experiment with the Barnett shale, spending millions of dollars.

Their success culminated in the $3.5 billion sale of the entire company to Devon Energy Corp. in 2002. The shale really took off after that when Devon applied horizontal drilling to it.

At a tribute dinner for George Mitchell at Hart Energy’s DUG Conference in Fort Worth in 2008, Devon’s then-chairman, Larry Nichols, spoke of the deal.

“We all know who the pioneer was in this play – it was George Mitchell. … He persevered for almost 20 years. In 1999 George tried to sell Mitchell Energy… it was a failed sale. No one bought it. We looked at it and didn’t buy it.

“But then, we looked at it again later. I noticed Mitchell’s gas production kept increasing, and I asked my guys to look into why. Devon bought it in 2002, and Wall Street yawned. One analyst even said we’d blow our brains out on it.

“Our plan was to take the hydraulic fracturing that George had begun and use that technique in the core area. … In 2003 we drilled the first horizontal well in Johnson County. By 2007 we were the first company to drill 1,000 horizontal wells out of a total of 4,000 drilled by the industry there.”

By year-end 2007 some 8,900 wells had been drilled in the Barnett shale, up 36% from the year before. A five-year leasing and drilling frenzy ensued across the US as producers looked for other shale plays and found them in the Haynesville, Woodford, Fayetteville, Eagle Ford, Bakken, Marcellus, and Utica.

Shale production has revolutionized the US gas market and is starting to do so for crude oil as well. The Potential Gas Committee said this year in its latest assessment that the US gas potential resource climbed to 67.5 Tcm (2,384 Tcf), the highest in the study’s 48-year history.

The shale story is still being written, but it was Mitchell and his team who opened the first chapter.

HIGHLIGHTS IN SHALE TIME

1981 Mitchell Energy & Development Corp. drills the C.W. Slay No. 1, the discovery well for the Newark East field (Barnett shale) in the Fort Worth basin.

1989 About 50 Barnett wells have been drilled in the Newark East field.

1991 Mitchell agrees to bring in the US Department of Energy and the Gas Research Institute to help, and the latter sponsor the first horizontal well in the Barnett.

1997 Mitchell does its first slickwater frac in May 1997, thereby cutting costs. Old-style massive fracs using lots of sand give way to smaller amounts of sand injected at higher rates. Microseismic fracture mapping, led by the Gas Research Institute, enables better understanding of the way natural fractures and induced fractures affect production in the shale.

2002 The Newark East field has now become one of the largest in Texas, producing from 900 wells. Devon Energy Corp. buys Mitchell Energy & Development Corp. for $3.5 billion, acquiring 71 Bcm (2.5 Tcf) of proved gas reserves in the play.

2003 Southwestern Energy Corp. launches a major leasing program in Arkansas’ Fayetteville shale.

2004 Range Resources Corp. drills its first Marcellus shale well in Pennsylvania. Southwestern Energy drills its first vertical wells in the Fayetteville.

2005 Range drills its first horizontal Marcellus well in Pennsylvania. Devon announces 56 horizontals and 70 verticals to be drilled in its Barnett core area. EOG Resources reports that a Barnett well tests at 283 Mcm/d (10 MMcf/d), and lease prices and rig counts are rising rapidly. Anadarko Petroleum starts building its Eagle Ford shale acreage position.

2006 Chesapeake Energy Corp. starts drilling the Haynesville shale.

2007 By year-end 2007 some 8,900 wells have been drilled in the Barnett, up 36% from the year before. Devon Energy announces it averaged 28.3 MMcm/d (1 Bcf/d) of Barnett production, the first company to do so, and, it drilled its 1,000th horizontal well in the play.

2008 Between January 2007 and December 2008, North American gas supply grows by 226 MMcm/d (8 Bcf/d), and shale gas reaches 18% of US supply.

Chesapeake Energy tells analysts the Haynesville could be bigger than the Barnett. Other E&Ps such as Petrohawk Energy Corp. and Cabot Oil & Gas begin to reveal their positions in the play. Estimates of 707 MMcm (25 Bcf) per section could be conservative.

Southwestern Energy says it has spent $2.6 billion in the Fayetteville and will drill 475 horizontal wells there this year.

2009 In September the Environmental Protection Agency issues the first of many information requests on the chemical composition of fluids used in fracturing as part of a broad scientific study requested by the US Congress. Requests go to service providers BJ Services, Complete Production Services, Halliburton, Key Energy Services, Patterson-UTI, PRC Inc., Schlumberger, Superior Well Services, and Weatherford.

As of year-end 2009, Newfield Exploration had drilled 30 horizontal Woodford shale wells in Oklahoma’s Arkoma basin, with an estimated internal rate of return of 35% if gas is $4.50/Mcfe.

2010 As oil prices rise and gas prices fall, more producers enter the rush to oily and liquids-rich shales. CNOOC forms a $2.6 billion joint venture (JV) with Chesapeake in the Eagle Ford, one of the highest per-acre valuations for Eagle Ford oil.

2011 The Barnett shale peaks at 170 MMcm/d (6 Bcf/d) in November. Statoil buys Bakken shale-focused Brigham Exploration Co. for $4.7 billion, and Carrizo Oil & Gas inks a JV with India’s GAIL in the Eagle Ford.

2012 Sumitomo Corp. invests $1.4 billion with Devon Energy in the Permian’s Cline and Wolfcamp shales. China announces a tender offer for 17 shale gas blocks. More than 70 companies express interest.

2013 In April the Potential Gas Committee finds, in its latest assessment, that the total US natural gas resource is now 26% higher than in any of its previous findings.

[ceo_energemsier + 1,818]

Lea advances to nation’s No. 2 county in oil production

 

We may be No. 2, but we try harder.

The old commercial line comes to mind when oil production data from various sources show Lea County hit the No. 2 spot in the nation in January.

According to County Finance Director Chip Low and Assistant County Manager Corey Needham, working the research together recently, Lea County produced 14.6 million barrels of oil in January.

Lea was second only to McKenzie County, N.D., which produced 17.3 million barrels the same month. Complete data for more recent months are not yet available.

A review of data for January 2019 from the U.S. Energy Information Administration, a division of the U.S. Department of Energy, indicates no appreciable change in the oil production rankings of states, leaving New Mexico in the No. 3 slot achieved last year. North Dakota still produces almost twice as much oil as New Mexico, but Texas produces more than three times as much as North Dakota.

At the same time, Lea County had more than twice the number of operating rigs as McKenzie County, 49-23, hence, the “we try harder” concept.

“These are what’s reported to the states,” Low said. “I can tell you that, now, Lea County is No. 2 in production. … It definitely impacts our revenue in a positive way, but it also means the need for more services.”

Steve Vierck, the out-going CEO and president of the Economic Development Corporation of Lea County, was pleased to hear the news.

“Our production has roughly tripled in the last five years,” Vierck said. “The county produces over half the state’s oil and the state is No. 3. It really reflects not only how much oil production there is, but how much growth there has been in oil production to move up the chart as fast as Lea County has.”

Vierck will join the New Mexico State Land Office next week, serving as economic advisor to the state land commissioner.

Sen. Gregg Fulfer, R-Jal, business owner in the oil and cattle sectors of southern Lea County and former chairman of the county commission doubts the peak has been reached.

“We may even become the top oil producer in the world by the time this is done, at least the Delaware Basin overall will be,” Fulfer said. “At one meeting I went to, they said there’s more oil per square foot than anywhere in the world right here in our area. It’s growing pretty quickly and we still haven’t seen the peak of the growth.”

He suggested some delay in growth may be attributed to lack of infrastructure including pipelines for natural gas and oil, and natural gas processing plants.

“I think that’s finally getting put in place. Every day more and more come on line, so I don’t think we’ve reached our peak by any means,” Fulfer said. “I think this is a longterm play and with the longterm play, we’re going to see huge investments going into our area.”

Vierck agreed, “Given what EDC has seen, it (Lea County oil production) hasn’t hit full stride yet.”

Weld County, Colo., slipped into third place in January with 13.7 million barrels produced. Other high producers were Midland County, Texas, 12.5 million barrels; Beachey Point County, Alaska, 11 million barrels; Eddy County, 10 million barrels; and Kern County, Calif., 9.9 million barrels.

In November, a group of major oil and gas companies with plays in the Permian Basin, a portion of which is the Delaware Basin that straddles the New Mexico-Texas border including the southern half of Lea County, announced the formation of an energy alliance, collectively committing more than $100 million over the next several years to spur additional private-sector investment in the region.

The 18 major oil companies that comprise the Permian Strategic Partnership said the Permian Basin is an oil-producing superpower, becoming one of the most strategically important oil-producing regions in the world, and leading the way to American energy independence.

The coalition says total oil production in the region is expected to more than double in the coming years due to advances in technology and improved operating efficiencies, creating tens of thousands of local jobs and generating billions in state and local tax revenues. The energy companies said while the oil and gas industry is inherently cyclical, they are convinced the Permian Basin is different from the boom-and-bust cycles of the past.

The unprecedented coalition of companies said it intends to address infrastructure challenges and strengthen communities across West Texas and southeast New Mexico. They said building new roads, recruiting new doctors and teachers and developing new neighborhoods will require years of work, substantial resources and sustained cooperation among many entities.

Permian Strategic Partnership member companies are: Anadarko, Apache, BPX Energy, Chevron, ConocoPhillips, Cimarex, Concho, Devon, Diamondback, Encana, Endeavor, EOG Resources, Halliburton, Occidental Petroleum, Parsley Energy, Pioneer, Plains All American, Schlumberger, Shell and XTO Energy.

[ceo_energemsier + 1,818]

Oil from US shale on track to rise 16% in 2019

HOUSTON, May 21

05/21/2019

 

US shale operators are on course to increase oil production markedly in 2019. The growth in US onshore production from the first quarter through the fourth quarter could come in at around 1.1-1.2 million b/d, or 16% for the full year, according to Rystad Energy.

After a paltry first quarter, depressed by weather effects, US shale players over the past weeks have assured investors that they will achieve previously communicated production targets, as well as demonstrate excellent capital discipline and cost control.

“Despite temporary challenges faced in the beginning of the year, E&P companies are set to deliver on their original production and capital targets, with some being well positioned to perform above initial expectations. US shale players can still be expected to deliver around 16% oil growth in 2019. Several operators have in fact raised their production guidance for the remainder of the year,” says Veronika Akulinitseva, senior analyst at Rystad Energy.

Rystad Energy has analyzed the first quarter results of about 50 US shale operators. The results indicate that US producers, on average, saw a slowdown in oil production growth in the first quarter. Output grew by 0.1% relative to the fourth quarter of 2018.

“The slow first quarter implies an even steeper expected growth curve for the remainder of the year. In fact, acceleration of oil production for many operators is already under way and oil additions are thus likely to increase notably already in the second quarter of 2019,” Akulinitseva said.

Canadian operator Enerplus was the player that raised its oil guidance the most, expecting 10% higher volumes than originally guided. It said growth is already under way and the company is aiming to generate a double-digit rise in production already in the second quarter. Likewise, SRC Energy, an independent operator in the Denver-Julesburg basin, raised its oil target by 7%, attributing the adjustment to overly conservative original guiding.

[ceo_energemsier + 1,818]

Cowen: E&Ps could return to growth if valuation stays down

Tracking by Cowen Inc., an American multinational investment bank, shows spending plans for 2019 by independent exploration and production firms are down 11%. Cowen expects independent E&Ps to honor capital discipline commitments for the remainder of this year, but if valuation remains depressed the group may pivot back toward growth.

Cowen tracks and analyzes capital spending for 50 pubic independent E&Ps as well as four majors: Chevron Corp., ExxonMobil Corp., BP PLC, and Royal Dutch Shell PLC.

Supermajors’ spending plans for this year are up about 24%. According to Cowen, supermajors likely maintain prior plans regardless of cash flow and continue to target mergers and acquisitions.

Independent E&Ps

Among the independents, Cowen finds budgets to be front-end loaded with 28% of planned 2019 spending completed in the first quarter, and with the second quarter looking flat to higher. Spending in the second half of the year could be down 14% sequentially.

“In prior years when E&Ps outspent during the first half, they would typically boost the budget midyear such that the second half would remain flat or even increase. Midyear budget increases were particularly common when commodity prices were supportive. While [West Texas Intermediate] has improved to $60[/bbl] from $45[/bbl] at the time many budgets were set, we expect commitments to capital discipline will leave plans unchanged, resulting in a second-half decline in spending and activity,” Cowen said.

Capital discipline commitments and higher oil prices will drive an inflection in E&P free cash flow (FCF) during this year’s second half. Cowen expects independent E&Ps to honor capital discipline commitments for the remainder of this year, but if valuation remains depressed, the group may pivot back toward growth.

“With the SPDR S&P Oil & Gas Exploration & Production ETF (XOP) up just 12% year-to-date while WTI is up 37%, the market is not rewarding the stocks. Should this continue, we see a reasonable chance E&Ps pivot back to growth over the next 2-3 quarters heading into 2020,” Cowen said.

Based on the investment bank’s current modeling, which reflects continued discipline, Cowen’s E&P coverage is assumed to grows capex by 3% in 2020 which equates to 77% of cash flow yielding 9% gains in production. However, if E&Ps pivot toward growth, even still spending just 90% of cash flow, capex could rise 30% and oil production 20%.

“While the stocks may not be getting credit for discipline, we suspect a pivot toward growth could be even worse for stock performance,” Cowen said, however.

Majors

Supermajors have refocused attention on developing US unconventional oil, demonstrated by Chevron and ExxonMobil’s multiyear Permian growth strategies and BP’s recent M&A activity.

“We see these companies executing growth plans over the next few years regardless of near-term cash flows. Moreover, following a demonstrated comfort with shale operations, we expect majors to pursue additional M&A, high-grading and expanding their shale footprints as potential valuation dislocation with independents emerge,” Cowen said.

“The supermajors made a late entrance into US shale, in some cases demonstrating patience in delineating acreage (Chevron) and in others using M&A to increase their footprint (BP, ExxonMobil). Now, the group is prioritizing US shale growth over the next 5 years. Specifically, the Permian presents a combination of high returns and relatively low above-ground risks that make it among the most competitive projects in the groups’ project hoppers.”

According to Cowen, the majors have the supplemental FCF and strong balance sheets to absorb negative FCF that accompany ramping up shale production and have plagued many of the independent E&Ps. The group has presented their shale plans with forecasts for turning FCF positive, acknowledging these assets will be FCF negative during development. The companies test their development plans across a range of price scenarios, making it likely the shale activity will be durable even if its positive FCF takes longer to materialize.

Chevron plans to increase Permian production from 400,000 boe/d in fourth-quarter 2018 to 900,000 boe/d at yearend 2023. The company has been rapidly increasing production since 2017 and plans on becoming FCF positive next year.

ExxonMobil will increase their Permian production from 200,000 boe/d in fourth-quarter 2018 to 1 million boe/d by 2024, hitting positive FCF in 2021.

BP expects to increase their transformed Lower 48 footprint from 300,000 boe/d to 500,000 boe/d and generate substantial FCF in 2021.

“In total, we estimate the group will increase shale spend, including on infrastructure, from about $7.5 billion in 2018 to $10 billion in 2019 and about $12 billion in 2020. We assume rig count will increase from 91 in 2019 to 113 in 2019 and 121 in 2020. Altogether we expect this program to result in an additional 162,000 b/d and 172,000 b/d of oil production in 2019 and 2020, respectively,” Cowen said.

Recent M&A activity demonstrates an interest in the group continuing to increase its US shale footprint, particularly in the Permian basin.

“We see the group as a natural consolidator given capacity to absorb near-term net cash outflows for longer-term upside. The potential for the group to consolidate additional shale acreage may suggest a rising floor to shale-related oil field service activity given the ability and desire for the group to spend through the cycle,” Cowen said.

[ceo_energemsier + 1,818]

New completion designs, breakevens help Bakken break records

A historic, decades-old oilfield in North Dakota is responsible for one of the highest barrel per day initial production rates ever recorded from a well on land in the U.S. The record-breaking well highlights how advanced completions in the Bakken shale play have become, and why the play is still leading the world in technological advancements deployed in the field. The Antelope field hosted a well that surpassed 10,000 barrels of oil per day (16,000 barrels of oil equivalent if the natural gas produced from the well was factored in), according to Lynn Helms, director of the department of mineral resources for North Dakota. Helms talked about the well and the impact of enhanced completions on the Bakken during his monthly update to industry and stakeholders.

“We are seeing the effects of remarkable wells,” he said. “There is almost no where you can drill where you can’t make money.”

New completion designs are expanding the perceived core of the Bakken and Three Forks formation by roughly 40 to 50 miles in some cases. According to Helms, the wells still decline but they start out with production rates that are 50 percent higher than previous versions and also remain producing at sustained levels that are also

50 percent higher than wells producing for a similar time frame that were also previously drilled and completed in a similar area.

“Virtually everywhere is economic,” he said.

Starting in mid-March, the Bakken reached roughly 25 frack crews after weather hampered operations in the Williston Basin for the winter months. By mid-summer, there should be approximately 50 frack crews operating in the state.  “Everything is moving at a rapid pace now. Road restrictions are off,” he said, adding that some counties have seen a big uptick in activity and workover and completion work is really taking off.

Later this year, oil production should once again begin breaking records. Natural gas production continues to rise. In March, natural gas production rose 6.5 percent from the previous month. Prices remain low for gas and natural gas liquid takeaway capacity still remains inadequate. Other states with shale gas plays have expressed similar issues as North Dakota, he noted, adding that all states are now accustomed to massive gas production volumes from new wells. In North Dakota, the volume of gas captured is at an all-time high, but supply is outpacing takeaway capacity.

On the crude-by-rail front, the state intends to file a lawsuit against the state of Washington related to new crude-by-rail vapor pressure restrictions the state has planned to start later this summer. According to Helms, the lawsuit is based on a violation of interstate commerce laws and the science behind the Washington law.

With 1,800 job openings for oil and gas positions in the state, Helms said they are also sharing the same issues of other states that have shale plays: they all need more workforce. The state has plans to develop new options for high school workers and streamline the process of getting into certain jobs. In the next two years, projections show the state will need to fill 3,500 jobs each year to meet the need of the oil and gas industry.

Permitting for new wells is still strong at roughly 100 to 150 permits per month. Oil prices are expected to rise due to global turmoil and throughout the year, Helms expects the Bakken and Three Forks (where 99 percent of the new wells are being drilled) to add drilling rigs.

[ceo_energemsier + 1,818]

Breakeven oil prices underscore shale’s impact on the market

By Michael Plante, Kunal Patel | May 21, 2019

 

The oil price that companies need to profitably drill new wells has closely tracked prices for long-dated oil futures in recent years. The emergence of U.S. shale production seems to be playing a large role in anchoring long-term oil prices.

The breakeven price—the price of oil needed to profitably drill a new well—is of great interest because it provides information on how activity in the oil sector might adjust if oil prices move dramatically. Its relevance has only grown over the past decade with the emergence of shale oil in the United States. Shale has a shorter lead time between drilling and production relative to offshore exploration

 

and other traditional oil projects, making it more responsive to oil price movements.

The average breakeven price of oil has fallen 4 percent (or $2 per barrel) over the past year, to $50 per barrel, according to the latest Dallas Fed Energy Survey. The $50 top-line figure masks some important differences. Areas such as the Midland and Delaware basins in the Permian Basin, hotbeds of shale activity, are routinely lower on average than other locations (Chart 1). There is also variability among operators; within the Permian Basin, for example, individual responses to the most recent survey ranged from $23 to $70.

Not All Basins Created Equal

A recurring feature of Dallas Fed Energy Survey breakeven prices is wide variation in responses, both across and within areas. The survey does not specifically define “profitable,” which introduces a human element that could contribute to some of the variation. More important is the reality that some areas are “sweet” spots, with lower costs and wells that are more productive.

One way to see this more concretely is to consider model-based breakeven prices produced by energy consulting firms. These models often allow one to vary assumptions about drilling costs, production levels and other factors among areas. Similar to the Dallas Fed survey results, model-based breakeven prices often show wide variability within and across areas.

For example, Bloomberg New Energy Finance’s breakeven prices in the Permian range from $46 per barrel in Loving County to $87 per barrel in Reagan County. The wide variability is largely driven by the quality of the rock, with wells in Loving County typically producing at higher rates and lower costs relative to Reagan County.

Breakevens Track Long-Dated Crude Oil Futures

A futures contract is a binding agreement to buy or sell a specific commodity for delivery on a specific date in the future. When we refer to the long-dated futures price, we mean the price of oil for delivery five years in the future.

With that in mind, there is a very close and interesting connection between average breakeven prices and the long-dated West Texas Intermediate futures contract (Chart 2). This is true not only for the Dallas Fed Energy Survey, but also for the Federal Reserve Bank of Kansas City’s energy survey.

How should we interpret the long-dated futures price of oil? In theory, if the oil market were perfectly competitive, the long-dated futures price should equal the marginal cost of supply—the cost of producing one additional unit—needed to meet long-run demand.

In reality, while it is true that most producers in the oil market are price takers—they produce a small amount of oil relative to global supply and their product has minimal differentiation—the oil market is not perfectly competitive: OPEC can add or withhold production because it operates with spare capacity. Nonetheless, there is still good reason to believe the long-dated futures price will have a close connection with the marginal cost of supply.

Shale Flattens Oil Cost Curve, Anchors Futures Prices

Rising U.S. shale production—likely to be a major source of incremental supply in coming years—has significantly affected the marginal cost of supply, providing a plausible link between the Dallas Fed average breakeven price and the long-dated futures price.

Horizontal drilling and hydraulic fracturing have made accessible significant amounts of oil reserves previously considered uneconomical to develop. Moreover, production costs for those reserves have declined dramatically over the past 10 years. More generally, companies have sought to lower costs associated with other, more traditional onshore and offshore oil holdings. As a result, larger quantities of oil are economical to produce at much lower prices than would have been possible before.

Recently evolving oil cost curves illustrate this development. An oil cost curve tries to provide information on how much extra supply could be forthcoming at a given price of oil. Usually the price of oil is shown on the left-hand axis. If the curve is upwardly steep, very high oil prices are needed to bring relatively small amounts of new production. A flat curve suggests the opposite.

Over the past 10 years, oil cost curves have moved from being very steep to having a long, flat portion between $50 and $60 as the industry has added resources and as costs have declined (Chart 3). In other words, shale production means there is a much larger amount of supply that can be called into action given a much smaller price increase than in the past.

While market participants may differ on how much oil is available at a given price, they are all aware of the overall trends. These represent strong forces that should keep long-dated futures prices from rising too high or falling too low. Similarly, breakeven prices reported by Dallas Fed Energy Survey participants reflect the principal trends involving the marginal cost of supply in the oil market.

Given current market prices, U.S. shale production will continue growing this year. Indeed, a recent report by the International Energy Agency highlighted that shale production is likely to be a major driver over the next five years. This does not rule out the possibility of major oil price movements, but it does point to a strong tendency that oil prices will be range bound in the near future.

-Plante is a senior research economist in the Research Department at the Federal Reserve Bank of Dallas.

-Patel is an associate economist in the Research Department at the Federal Reserve Bank of Dallas.

 

 

 

[ronwagn + 6,290]

21 hours ago, ceo_energemsier said:

Crude Exporters Navigate Gulf Coast Terminal Constraints

 

U.S. crude exports out of the Gulf Coast averaged more than 2.4 MMb/d in the first four months of 2019 — using infrastructure that is increasingly constrained by a lack of deepwater ports. U.S. crude is reaching destinations worldwide, with large volumes traveling long distances to Asia on gargantuan 2-MMbbl vessels — Very Large Crude Carriers (VLCCs) — loaded offshore by ship-to-ship transfer. Shipments to Europe are primarily on smaller Suezmax and Aframax vessels. Overall, the increased marine activity is testing the limits of existing infrastructure. the past 16 months of crude export vessel movements and their impacts on Gulf Coast ports.

 

the development of U.S. crude exports since the ban on most overseas shipments was lifted in December 2015. Exports from the Gulf Coast are growing and expected to increase further as new pipelines from the Permian and Eagle Ford come online over the next two and a half. In the less than four years since wide-open exporting began, the rapidly developing export market has overcome a number of challenges, like poor price transparency and the lack of deepwater terminals to load exports Actual shipments still require considerable logistical juggling as crude is loaded from smaller tankers onto long-distance VLCCs for voyages to Asia. ports like the Houston Ship Channel are contending with increased congestion and the resulting difficulties in scheduling. Plans to expand the onshore ports — and build new deepwater terminals offshore — are in the works, but funding and executing on these projects is not easy and can take many years.

 

 

 

We reviewed every export shipment from Gulf Coast ports between January 1, 2018 and April 24, 2019, including the size of vessel, load terminal and ultimate destination as well as ship-to-ship transfers onto larger tankers. We’ll begin our discussion of what we learned with a closer look at port activity, then break down the characteristics of crude ship movements affecting marine traffic in the Gulf.

 

 

 

 

 

 

 

Size Matters

 

 

 

With the exception of the Louisiana Offshore Oil Port (LOOP) terminal 20 miles off the Louisiana coast in the Gulf of Mexico, the Gulf Coast is not blessed with deepwater ports that can accommodate massive VLCCs. These supertankers and a handful of their giant brethren — the 3-MMbbl Ultra Large Crude Carriers (ULCCs) — require at least a 75-feet of draft to load fully and are the workhorses of long-distance oil transport between continents. Most Gulf Coast terminals are restricted to a 45-foot draft that only allows them to fully load Aframax tankers holding 500-650 MBbl of crude or to partially load Suezmax tankers that hold up to 1.3 MMbbl. Analysis of the  data shows that during the 16-month period from January 2018 to April 2019, 548 different vessels made a total of 1,402 crude export shipments from Gulf Coast terminals. Of these shipments, 69% involved Aframax tankers, 21% Suezmax, and 6% smaller Panamax (less than 500 Mbbl); 3% were loaded directly onto VLCCs. (As we’ll get to in a bit, many of the smaller tanker loadings were for ship-to-ship transfers to VLCCs.)

 

 

 

Load Terminals

 

 

  

Figure 1 lists the top 15 export terminals by throughput volume over the analysis period. Enterprise Products Partners’ Enterprise Hydrocarbons Terminal (EHT) in the Houston Ship Channel (HSC) is the Gulf Coast’s busiest crude export terminal, followed by Energy Transfer’s Nederland terminal in Port Arthur, TX, and Moda Midstream’s Ingleside Corpus Christi terminal in third place.

 

 

 

 

In addition to its terminal on the HSC, Enterprise also operates the fifth and sixth busiest Houston-area terminals: Seaway Texas City and Seaway Freeport. Other top 15 terminals in the Houston region include SemGroup’s Houston Fuel Oil Terminal and the Magellan/LBC Seabrook terminal.

 

The second busiest crude oil export terminal on the Gulf Coast is Energy Transfer’s Nederland facility, which has 27 MMbbl of storage capacity and pipeline connections from Cushing (TC Energy’s Cushing Marketlink), the Permian (Energy Transfer’s Permian Express and West Texas Gulf pipelines), Houston (Shell Midstream’s Zydeco pipeline) and North Dakota (the Dakota Access Pipeline and the Energy Transfer Crude Oil Pipeline, better known as ETCOP). Nederland has five tanker berths that can fully load Aframax vessels with a 40-foot draft and partially load a Suezmax. Energy Transfer Nederland loaded 146 Aframax and 62 Suezmax tankers between January 1, 2018 and April 24, 2019.

 

 

 

Third place among Gulf Coast crude export terminals belongs to the Moda Ingleside Energy Center located in the outer harbor of Corpus Christi. Moda purchased the terminal from Occidental in August 2018, and Oxy remains its principal customer. The purpose-built crude export terminal can partially load VLCCs and Suezmax tankers at three deepwater berths. Export capacity is currently being expanded from 300 Mb/d to 750 Mb/d and the channel draft is being deepened to 54 feet to accommodate fully laden Suezmax tankers. Moda Ingleside receives crude from the Permian and South Texas Eagle Ford basins. The terminal loaded 83 Aframax, 33 Suezmax and 22 partially loaded VLCC tankers between January 1, 2018 and April 24, 2019.

 

 

 

During the 16-month period of our analysis, 38% of export shipments were from the Houston region — encompassing the HSC, Texas City, Freeport and Seabrook terminals. The Beaumont/Port Arthur region was second busiest, with 26% of export volumes leaving three facilities: Energy Transfer’s Nederland terminal (mentioned above) and Phillips 66 and Enterprise terminals in Beaumont. Shipments out of Beaumont/Port Arthur just beat volumes leaving the Corpus Christi area (25% of the total), which includes the Buckeye, NuStar and Valero terminals in the Corpus Christi Ship Channel, as well as the Flint Hills Resources (a.k.a. Koch Industries) and Moda terminals at Ingleside. Louisiana accounted for the smallest share of crude export volume leaving the Gulf Coast; the state accounted for 12% of the total. These shipments were made from LOOP in the Gulf of Mexico , the NuStar and Plains terminals in St. James, LA, as well as a few refinery terminals along the Mississippi

 

 

Despite the preponderance of exports loading onto Aframax tankers, most long-distance crude shipments from the Gulf Coast to buyers in Asia are made on VLCCs, because these supertankers boast the most competitive freight rates (see Rock The Boat). Since the direct loading of VLCCs can only happen at deepwater ports like LOOP, it’s common practice to use Aframax and Suezmax tankers to make ship-to-ship transfers (STSs) onto VLCC tankers located in offshore Gulf of Mexico loading zones. These STSs, also known as reverse lightering, allow shippers to load a full VLCC cargo for onward shipment from the Gulf. Our data shows that just under half (or 46%) of the crude export vessels loaded at Gulf Coast ports were for ship-to-ship transfers, with crude loaded onto the smaller tankers at port subsequently loaded onto VLCCs. The data further shows that 85% of Aframax and 76% of Suezmax STS transfers were made onto VLCCs destined for Asia (bottom chart in Figure 2). While VLCCs are popular for the longer-haul Asia runs, smaller Aframax and Suezmax vessels are most popular for shipments to Europe (top chart in Figure 2). During the 16-month analysis period, a total of 306 Aframax and 85 Suezmax tankers were loaded directly (without transfers) for voyages to Europe.

 

The detailed logistics involved in getting U.S. crude out of Gulf Coast terminals and on their way to export markets underlines the ingenuity of shippers that have built export volumes from next to nothing to more than 2.4 MMb/d in just four years. The upcoming tsunami of crude from new pipelines out of the Permian and Eagle Ford over the next two years will surely test the export infrastructure. That’s the reason behind a slew of new project proposals to build deepwater Gulf of Mexico terminals off the coast of Freeport (TX), Texas City (TX), Corpus Christi, Brownsville (TX) and Louisiana, as well as plans to expand part of the Corpus Christi harbor channel to accommodate fully loaded. If one or more of the new deepwater terminals are built, they would reduce the number of ship-to-ship transfers needed to load export cargoes. Then, in theory at least, pipelines could seamlessly feed deepwater terminals and load VLCC tankers directly and efficiently. If for any reason those deeper terminals don’t get built, expect to see increased congestion as existing Gulf Coast docks struggle to handle ever-larger crude export volumes.

 

 

 

 

 

 

 

 

What about using FLNG terminals rather than land based.  https://en.wikipedia.org/wiki/Floating_liquefied_natural_gas

The FLNG would be used only to receive, liquefy and load the LNG onboard the LNG tankers. This might reduce compaction of the area and allow more space. NLNGs can also be moved around the world where and when needed. 

[ceo_energemsier + 1,818]

11 hours ago, ronwagn said:

What about using FLNG terminals rather than land based.  https://en.wikipedia.org/wiki/Floating_liquefied_natural_gas

The FLNG would be used only to receive, liquefy and load the LNG onboard the LNG tankers. This might reduce compaction of the area and allow more space. NLNGs can also be moved around the world where and when needed. 

Good point, there are talks about that happening between different companies, one problem that is a big issue is the delivery of natural gas to the FLNG fron onshore sources. The infrastructure build out (pipelines, pumping stations, docks, jetties, dredging and prep work for laying under water pipelines from shore to the FLNG location to deliver the gas), would be very expensive and facing many technical and other challenges. FLNG will be best suited for its intended purpose of receiving and procssing natgas from offshore producing fields, and then be loaded onto LNG tankers. The FLNG like the FPSO has the ability and the flexibility to be relocated very easily after one project is completed upon the depletion of the resource field and decommissioning of the offshore production facilities, but that takes years, decades to deplete and move on.

[ceo_energemsier + 1,818]

14 hours ago, ronwagn said:

What about using FLNG terminals rather than land based.  https://en.wikipedia.org/wiki/Floating_liquefied_natural_gas

The FLNG would be used only to receive, liquefy and load the LNG onboard the LNG tankers. This might reduce compaction of the area and allow more space. NLNGs can also be moved around the world where and when needed. 

Petronas achieved its first liquefied natural gas (LNG) drop by its floating LNG facility, PETRONAS Floating LNG Satu (PFLNG Satu), at the Kebabangan cluster field, 90 kms offshore Sabah, recently. Operated by Kebabangan Petroleum Operating Company (KPOC), Kebabangan field is the second location for PFLNG Satu after its successful operation in Kanowit field, Sarawak.

The introduction of first gas into the PFLNG Satu, achieved on 4th May 2019, was from Kebabangan field to the PFLNG Satu’s turret system via a 5-km flexible pipeline. The commencement of a series of start-up activities included the cooling down of natural gas until the production of the first LNG drop on 7th May 2019, just 3 days after.
 
PETRONAS Vice President of LNG Asset Zakaria Kasah said:

'This achievement showcases our focused execution and close collaboration efforts, within PETRONAS as well as externally with the State government and regulatory bodies. We not only prove our concept of relocatable floating LNG facility, but we have also seamlessly achieved the first LNG drop in just 3 days after first gas in. This is indeed another proud moment and a great milestone for PETRONAS and the floating LNG industry.'
 
Designed for water-depth of between 70 metres and 200 metres and a processing capacity of 1.2 million tonnes per annum (MTPA) with 155 crew onboard, PFLNG Satu will support PETRONAS’ global LNG portfolio and enhance its reputation as a preferred and reliable LNG supplier. The first LNG cargo delivery at the new field is expected in June, 2019.

[ceo_energemsier + 1,818]

Sasol raises cost estimate for U.S. plant by around $1 billion

JOHANNESBURG (Reuters) - Sasol has raised the expected cost of its U.S. ethane cracker project by around $1 billion following a review by the project’s new management, the South African petrochemicals firm said on Wednesday, sending its shares more than 10% lower.

The estimate for the Lake Charles Chemicals Project (LCCP), which will convert natural gas into plastics ingredient ethylene, is now $12.6-12.9 billion, including a contingency of $300 million, Sasol said in a stock exchange announcement.

The company said the review of the project, which was initially expected to cost $8.9 billion in 2014, revealed oversights such as duplicate credits and overlooked contracts, adjustments for potential insurance claims, procurement back-charges and remaining work and repairs that needed to be done.

“We are extremely disappointed with the increase in LCCP’s capital costs. We take accountability and we are confident that the revised plan will be delivered,” said joint president and chief executive officer Bongani Nqwababa on a conference call.

Sasol had said in February the plant in Louisiana, which saw the first of seven units start production earlier this year, was expected to cost up to $11.8 billion.

 

Shares in Sasol, the world’s biggest maker of motor fuel from coal, were down 12.5 percent to 377.45 rand at 0753 GMT.

“The numbers just don’t look very flattering at all,” said Ryan Woods, market trader at Independent Securities.

Sasol also cut the forecast return from the project to 6-6.5% from 7.5% due to the increased cost as well as the outlook for market prices.

It reduced the project’s expected earnings before interest, tax, depreciation and amortization (EBITDA) for the 2022 financial year to $1 billion from $1.3 billion.

Sasol said the project was 96% complete, with capital expenditure at $11.4 billion as of the end of March.

 

The cost increase will result in higher gearing - net debt to EBITDA - for Sasol for 18 to 24 months, with gearing expected to peak at 2-2.3 times during fiscal 2019, the company said.

“We believe that the balance sheet is sufficiently robust to absorb the increase in cost and our capital allocation strategy is unchanged. We remain confident for the long-term outlook for the LCCP,” said Nqwababa.

Sasol, which has plans to offload around $2 billion in assets across its portfolio, said the sales would further support deleveraging.

[ceo_energemsier + 1,818]

Saudi Aramco buys US LNG supplied by shale gas!!!!!!!!!!!!!!!!!!

 

 

Saudi Aramco signs US LNG deal in bid to diversify beyond oil

Deal with Sempra Energy includes 20-year natural gas supply agreement 

https://www.ft.com/content/a7d007f0-7c5f-11e9-81d2-f785092ab560

 

 

https://af.reuters.com/article/commoditiesNews/idAFL5N22Y172

[ceo_energemsier + 1,818]

Growing exports add to annual hurricane risks for US energy sector

Global flows now at stake in storm threat

Crude, gas exports have tripled since Harvey

Demand destruction remains top power concern

 

 

Washington — As the US becomes a larger oil and gas exporter, the annual threat from the Atlantic hurricane season poses greater risks for global flows, on top of the usual risks to electricity demand and domestic fuel supplies.

The US exports more than three times as much crude oil and LNG as it did when Hurricane Harvey hit the Houston area in August 2017. The storm did massive damage across the energy and shipping sectors, roiling markets for weeks.

"Another Hurricane Harvey-type event would cause big problems for exporters if the port infrastructure was closed down," said Sandy Fielden, director of oil and products research for Morningstar Commodity Research. "Of course the impact of a hurricane varies with its intensity and direction, but could obviously be significant."

Port closures could ripple across the new oil export infrastructure -- canceling vessel loadings, filling storage terminals and backing up pipelines.

However, the pipeline and terminal buildout that has happened as a result of booming onshore production adds flexibility to reroute flows if one port is disrupted.

"A lot of these shippers are large enough to want exposure to multiple markets. They don't want a hurricane shutting their entire production field," said Jeremy Goebel, executive vice president of Plains All American, a major player in the buildout of Permian oil pipelines.

"We're trying to create a mousetrap in the Permian Basin and the Mid-Continent that touches St. James, Nederland, Houston and Corpus to allow for the most flexibility, flow assurance and quality control," he said during the company's May earnings call.

 

 

The National Oceanic and Atmospheric Administration will release its forecast for the 2019 hurricane season Thursday. The season runs from June 1 to November 30, with the most active period typically in mid-August through October.

Other potential energy impacts from hurricane season:

• Destruction of power, gas, nuclear demand
• Offshore oil, gas platform evacuations
• Refiners getting cut off from crude supply
• Localized gasoline, diesel shortages
• Calls for Jones Act waivers, SPR releases

MIDSTREAM BUILDOUT TO HELP KEEP OIL FLOWING

The US oil sector is banking on major new pipeline routes to help producers and refiners reroute flows around a potential disruption.

The April startup of the final section of Energy Transfer's 480,000 b/d Bayou Bridge pipeline, for example, allows southeast Louisiana refiners to continue receiving Permian and other Mid-Continent crudes via Nederland, Texas, if a storm cuts off other routes.

The Trump administration's willingness to waive the Jones Act -- which bars non-US vessels from delivering goods between US ports -- will depend on the severity of a storm and any resulting fuel shortage. Meanwhile, oil prices will be a main factor in whether the White House decides to tap the Strategic Petroleum Reserve.

Bakken producer Continental Resources sees the annual storm threat the same way as it treats challenging weather at its fields in North Dakota.

"Every year winter comes, and every year we deal with it," said Blu Hulsey, Continental's senior vice president of government relations and regulatory affairs. "We're a resilient industry that is able to supply our purchasers with the crude they need internationally and domestically."

GAS SECTOR GIRDS FOR DEMAND DESTRUCTION

For the gas sector, hurricanes pose a significant threat of destroying demand by knocking out large swaths of power generation as well as potentially shutting in one of the nation's four operating LNG export terminals.

Before the rise in US onshore production, the industry's main threat during hurricane season was to shut-in production in the offshore Gulf of Mexico. However, offshore gas production has plunged to 3.2 Bcf/d on average this year, compared with 11.1 Bcf/d in the same period of 2005, according to S&P Global Platts Analytics.

By contrast, gas demand from power generation in the US Southeast and Texas has nearly doubled to about 14.1 Bcf/d last year, from 7.6 Bcf/d in 2005.

On October 11, the day after Hurricane Michael made landfall on the Florida Panhandle, widespread power outages caused Southeast sample demand to fall to 19.8 Bcf/d based on evening cycle nominations, down 1.3 Bcf/d day on day, according to Platts Analytics data.

Risks to gas demand also include the growing list of liquefaction facilities exporting LNG. Four have started up since 2016, with another two expected in the near future.

The total LNG feedgas demand from all six fully operational LNG terminals could be upwards of 11.3 Bcf/d, Platts Analytics data showed.

Three LNG terminals operating along the Gulf Coast and one on the East Coast lie within the potential paths of tropical storms and hurricanes. Cameron LNG, which began exporting LNG from its Louisiana terminal on May 14, had received feedgas flows of 254 MMcf/d as of May 1, according to Platts Analytics data.

Feedgas flows to Cheniere Energy's Sabine Pass terminal in Louisiana were reported at about 3.9 Bcf/d, while the company's Corpus Christi, Texas, terminal saw feedgas flows of 718 MMcf/d.

Dominion Energy's Cove Point terminal in Maryland recorded feedgas flows of 707 MMcf/d as of May 1, Platts Analytics data showed.

While LNG terminals are designed to withstand the direct impacts of the most powerful hurricanes and their accompanying storm surges, the knockoff effects of hurricanes could cause the plants to limit or suspend operations.

Hurricane Harvey caused massive widespread flooding that cut off gas supplies from processing facilities in the Eagle Ford producing region of South Texas from reaching the Gulf Coast. Harvey also caused construction delays at Freeport LNG's export project.

POWER SECTOR AIMS FOR QUICKER RECOVERIES

The US power sector is hoping to improve the time it takes to restore power to homes and businesses after storms with improved resource management and new technologies.

The large influx of petrochemical, LNG and refinery development along the Texas and Louisiana coasts in recent years means the impact of power losses could be magnified.

The five storms that hit the mainland US in 2017 and 2018 cut power demand, at their peak, by levels ranging from less than 7% for Hurricane Nate in October 2017, when it hit the Louisiana area of the Midcontinent Independent System Operator, to more than 70% for Hurricane Irma in September 2017, when it hit Florida. During Irma, natural gas flows to the state's power plants were down 2.5 Bcf/day, according to Platts Analytics.

Hurricane power demand effects
Storm	Area	Landfall	GW reduction	% reduction
Harvey	ERCOT	25-Aug-17	24.4	37.3%
Irma	Florida	10-Sep-17	25.9	71.1%
Nate	Louisiana	8-Oct-17	6.1	6.8%
Florence	Carolinas	14-Sep-18	14.4	39.1%
Michael	Florida	10-Oct-18	5	12.0%
Source: US Energy Information Administration

Hurricane Harvey dealt a huge blow to the refining and petrochemical complex near Houston.

For the hour ending at 6 pm August 27, the peak of the Harvey outages, loads in the Electric Reliability Council of Texas were about 24.4 GW, or 37.3%, lower than on the same day of the previous week, but peakloads did not return to average until a week later, September 3.

The average here refers to an average of the same periods of 2015, 2016 and 2018, so as to reflect recent industrial development in the area. The hourly demand data is from the US Energy Information Administration, and the peakload data is from ERCOT.

Natural gas power plant demand fell by as much as 0.5 Bcf/day during a five-day sample after Harvey, according to Platts Analytics.

ERCOT Hub real-time on-peak locational marginal prices returned to the average on September 3, 2017.

"Demand decreases during serious storms and wholesale prices follow suit," said Matthew Cordaro, former MISO president and CEO. "This is usually a temporary situation but can be extended as quick repairs made in restoration are made permanent."

Some hurricanes result in power outages lasting weeks and months, such as Hurricane Maria devastating Puerto Rico in September 2017. Other storms cause major initial outages that can be restored relatively quickly, such as Hurricane Florence's effect on the Carolinas in September 2018. Up to 1.3 million customers lost power initially, which shrank to less than 180,000 five days later.

Wei Du, a PA Consulting energy and utilities expert focused on utility reliability, attributed part of improved service restoration efforts in recent years to better resource management and technology.

"Substation flood censors and preemptively de-energizing substations prior to the flooding of critical energized equipment is one aspect that helps quicken the pace of restoration," Du said.

Utilities such as the Houston area's CenterPoint Energy have also touted the deployment of advanced metering devices and drones that can be used to inspect power lines without dispatching inspection crews by truck through flooded streets.

[ceo_energemsier + 1,818]

Just now, ceo_energemsier said:

Growing exports add to annual hurricane risks for US energy sector

Global flows now at stake in storm threat

Crude, gas exports have tripled since Harvey

Demand destruction remains top power concern

 

 

Washington — As the US becomes a larger oil and gas exporter, the annual threat from the Atlantic hurricane season poses greater risks for global flows, on top of the usual risks to electricity demand and domestic fuel supplies.

The US exports more than three times as much crude oil and LNG as it did when Hurricane Harvey hit the Houston area in August 2017. The storm did massive damage across the energy and shipping sectors, roiling markets for weeks.

"Another Hurricane Harvey-type event would cause big problems for exporters if the port infrastructure was closed down," said Sandy Fielden, director of oil and products research for Morningstar Commodity Research. "Of course the impact of a hurricane varies with its intensity and direction, but could obviously be significant."

Port closures could ripple across the new oil export infrastructure -- canceling vessel loadings, filling storage terminals and backing up pipelines.

However, the pipeline and terminal buildout that has happened as a result of booming onshore production adds flexibility to reroute flows if one port is disrupted.

"A lot of these shippers are large enough to want exposure to multiple markets. They don't want a hurricane shutting their entire production field," said Jeremy Goebel, executive vice president of Plains All American, a major player in the buildout of Permian oil pipelines.

"We're trying to create a mousetrap in the Permian Basin and the Mid-Continent that touches St. James, Nederland, Houston and Corpus to allow for the most flexibility, flow assurance and quality control," he said during the company's May earnings call.

 

 

The National Oceanic and Atmospheric Administration will release its forecast for the 2019 hurricane season Thursday. The season runs from June 1 to November 30, with the most active period typically in mid-August through October.

Other potential energy impacts from hurricane season:

• Destruction of power, gas, nuclear demand
• Offshore oil, gas platform evacuations
• Refiners getting cut off from crude supply
• Localized gasoline, diesel shortages
• Calls for Jones Act waivers, SPR releases

MIDSTREAM BUILDOUT TO HELP KEEP OIL FLOWING

The US oil sector is banking on major new pipeline routes to help producers and refiners reroute flows around a potential disruption.

The April startup of the final section of Energy Transfer's 480,000 b/d Bayou Bridge pipeline, for example, allows southeast Louisiana refiners to continue receiving Permian and other Mid-Continent crudes via Nederland, Texas, if a storm cuts off other routes.

The Trump administration's willingness to waive the Jones Act -- which bars non-US vessels from delivering goods between US ports -- will depend on the severity of a storm and any resulting fuel shortage. Meanwhile, oil prices will be a main factor in whether the White House decides to tap the Strategic Petroleum Reserve.

Bakken producer Continental Resources sees the annual storm threat the same way as it treats challenging weather at its fields in North Dakota.

"Every year winter comes, and every year we deal with it," said Blu Hulsey, Continental's senior vice president of government relations and regulatory affairs. "We're a resilient industry that is able to supply our purchasers with the crude they need internationally and domestically."

GAS SECTOR GIRDS FOR DEMAND DESTRUCTION

For the gas sector, hurricanes pose a significant threat of destroying demand by knocking out large swaths of power generation as well as potentially shutting in one of the nation's four operating LNG export terminals.

Before the rise in US onshore production, the industry's main threat during hurricane season was to shut-in production in the offshore Gulf of Mexico. However, offshore gas production has plunged to 3.2 Bcf/d on average this year, compared with 11.1 Bcf/d in the same period of 2005, according to S&P Global Platts Analytics.

By contrast, gas demand from power generation in the US Southeast and Texas has nearly doubled to about 14.1 Bcf/d last year, from 7.6 Bcf/d in 2005.

On October 11, the day after Hurricane Michael made landfall on the Florida Panhandle, widespread power outages caused Southeast sample demand to fall to 19.8 Bcf/d based on evening cycle nominations, down 1.3 Bcf/d day on day, according to Platts Analytics data.

Risks to gas demand also include the growing list of liquefaction facilities exporting LNG. Four have started up since 2016, with another two expected in the near future.

The total LNG feedgas demand from all six fully operational LNG terminals could be upwards of 11.3 Bcf/d, Platts Analytics data showed.

Three LNG terminals operating along the Gulf Coast and one on the East Coast lie within the potential paths of tropical storms and hurricanes. Cameron LNG, which began exporting LNG from its Louisiana terminal on May 14, had received feedgas flows of 254 MMcf/d as of May 1, according to Platts Analytics data.

Feedgas flows to Cheniere Energy's Sabine Pass terminal in Louisiana were reported at about 3.9 Bcf/d, while the company's Corpus Christi, Texas, terminal saw feedgas flows of 718 MMcf/d.

Dominion Energy's Cove Point terminal in Maryland recorded feedgas flows of 707 MMcf/d as of May 1, Platts Analytics data showed.

While LNG terminals are designed to withstand the direct impacts of the most powerful hurricanes and their accompanying storm surges, the knockoff effects of hurricanes could cause the plants to limit or suspend operations.

Hurricane Harvey caused massive widespread flooding that cut off gas supplies from processing facilities in the Eagle Ford producing region of South Texas from reaching the Gulf Coast. Harvey also caused construction delays at Freeport LNG's export project.

POWER SECTOR AIMS FOR QUICKER RECOVERIES

The US power sector is hoping to improve the time it takes to restore power to homes and businesses after storms with improved resource management and new technologies.

The large influx of petrochemical, LNG and refinery development along the Texas and Louisiana coasts in recent years means the impact of power losses could be magnified.

The five storms that hit the mainland US in 2017 and 2018 cut power demand, at their peak, by levels ranging from less than 7% for Hurricane Nate in October 2017, when it hit the Louisiana area of the Midcontinent Independent System Operator, to more than 70% for Hurricane Irma in September 2017, when it hit Florida. During Irma, natural gas flows to the state's power plants were down 2.5 Bcf/day, according to Platts Analytics.

Hurricane power demand effects
Storm	Area	Landfall	GW reduction	% reduction
Harvey	ERCOT	25-Aug-17	24.4	37.3%
Irma	Florida	10-Sep-17	25.9	71.1%
Nate	Louisiana	8-Oct-17	6.1	6.8%
Florence	Carolinas	14-Sep-18	14.4	39.1%
Michael	Florida	10-Oct-18	5	12.0%
Source: US Energy Information Administration

Hurricane Harvey dealt a huge blow to the refining and petrochemical complex near Houston.

For the hour ending at 6 pm August 27, the peak of the Harvey outages, loads in the Electric Reliability Council of Texas were about 24.4 GW, or 37.3%, lower than on the same day of the previous week, but peakloads did not return to average until a week later, September 3.

The average here refers to an average of the same periods of 2015, 2016 and 2018, so as to reflect recent industrial development in the area. The hourly demand data is from the US Energy Information Administration, and the peakload data is from ERCOT.

Natural gas power plant demand fell by as much as 0.5 Bcf/day during a five-day sample after Harvey, according to Platts Analytics.

ERCOT Hub real-time on-peak locational marginal prices returned to the average on September 3, 2017.

"Demand decreases during serious storms and wholesale prices follow suit," said Matthew Cordaro, former MISO president and CEO. "This is usually a temporary situation but can be extended as quick repairs made in restoration are made permanent."

Some hurricanes result in power outages lasting weeks and months, such as Hurricane Maria devastating Puerto Rico in September 2017. Other storms cause major initial outages that can be restored relatively quickly, such as Hurricane Florence's effect on the Carolinas in September 2018. Up to 1.3 million customers lost power initially, which shrank to less than 180,000 five days later.

Wei Du, a PA Consulting energy and utilities expert focused on utility reliability, attributed part of improved service restoration efforts in recent years to better resource management and technology.

"Substation flood censors and preemptively de-energizing substations prior to the flooding of critical energized equipment is one aspect that helps quicken the pace of restoration," Du said.

Utilities such as the Houston area's CenterPoint Energy have also touted the deployment of advanced metering devices and drones that can be used to inspect power lines without dispatching inspection crews by truck through flooded streets.

It is too bad that the USWC States wont allow infrastructure (pipelines and terminals) to be built , as another alternate export and crude/gas/product movement route

One viable and alternate route under negotiations is with Mexico to build pipelines to go through sparsely populated areas and onto the Pacific coast with a deep water port, LNG facility and export terminal for crude etc.

[ceo_energemsier + 1,818]

Occidental To Remove CO2 From Air, Use It To Boost Oil Recovery In The Permian

https://oilprice.com/Latest-Energy-News/World-News/Occidental-To-Remove-CO2-From-Air-Use-It-To-Boost-Oil-Recovery-In-The-Permian.html

[ceo_energemsier + 1,818]

Aramco Taps into US Shale Gas Boom

Saudi Aramco agreed to a buy a stake in Sempra Energy’s Texas LNG export terminal, giving the world’s biggest oil exporter a foothold in the fast-growing global gas trade.

The proposed deal, which also includes an agreement to buy gas from the plant, would mark Aramco’s first entry into production of oil or gas outside Saudi Arabia. Aramco can potentially ship the LNG home to the kingdom’s power plants or trade it globally. The state-owned company and Sempra signed a preliminary agreement to acquire a 25% stake in the plant, but didn’t disclose the value of the potential deal.

A recent transaction could give a guideline for what the deal is worth. France’s Total SA paid about $1.5 billion for the LNG assets of utility Engie SA, which included shares in Sempra’s Cameron LNG plant in the U.S.

Saudi Arabia is tapping into the U.S. shale revolution, joining a wave of LNG exporters that will primarily ship the fuel to buyers in Europe and Asia. Sempra itself is working on five projects. Both the U.S. and Australia could overtake Qatar as the world’s biggest LNG supplier in coming years.

Aramco sees annual demand for LNG rising about 4% a year and reaching 500 million metric tons a year by 2035. Global demand for LNG, which is gas that is super-chilled until it turns to liquid and can be transported by tankers, was 324 million tons last year according to BloombergNEF.

Saudi Arabian Oil Co., as Aramco is officially known, would buy 5 million tons of LNG a year from Sempra over 20 years if the deal is completed, the companies said in a statement. The gas will be produced from Phase 1 of Sempra’s Port Arthur LNG project. The companies also agreed to negotiate Aramco’s purchase of a 25% stake in that phase.

The agreement “is a major step forward in Saudi Aramco’s long term strategy to become a leading global LNG player,” Chief Executive Officer Amin Nasser said in a statement. “We will continue to pursue strategic partnerships which enable us to meet rising global demand for LNG.”

In a region richly endowed with hydrocarbons, Aramco has struggled to build its gas business fast enough to keep pace with surging domestic demand. Past joint ventures with companies like Royal Dutch Shell Plc, Eni SpA and Lukoil PJSC found gas in the kingdom’s vast Rub al Khali desert, known as the Empty Quarter, but it was too expensive to develop.

That forced Nasser to adapt the company’s strategy, exploring for shale at home and seeking acquisitions abroad. Aramco traded its first LNG cargo in March and said it’s seeking gas resources in the U.S., Russia and Australia, and it began producing gas from shale deposits in the kingdom last year.

Pushing into gas adds to the rivalry between Saudi Arabia and its regional foes Iran and Qatar. Iran holds reserves second only to Russia’s, but sanctions and lack of investment stymied its export plans. Qatar is the world’s biggest LNG exporter and is a partner with Exxon Mobil Corp. in a $10 billion plant in Texas, and has plans to pour a total of $20 billion into U.S. oil and gas fields.