U.S. Shale Output may Start Dropping Next Year

On 3/18/2019 at 10:58 AM, Jeff_Calgary said:

If I were king I would be making the industry incinerate rather than flare. It does not cost much more but is way better. Destroys the methane and the BTEX.

They should use it on site, ship it by truck,  or get out of the business. Let the big companies, that will do it, take over.Your idea is better than flaring though. 

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3 hours ago, ronwagn said:

They should use it on site, ship it by truck,  or get out of the business. Let the big companies, that will do it, take over.Your idea is better than flaring though. 

I mentioned some where else on this forum recently and last year about the various options for produced gas before pipelines and processing/gathering facilities are in place to prevent the flaring.

1) Produced gas reinjection into the formation or into another zone for later use and or increasing liquid hydrocarbons production volume. We tried that in several different parts of the country and different countries and it worked well. Saved a valuable resource for future use and also prevented the air quality issues etc.

2) Compact GTL plants that would convert the gas to liquids fuels . There are several companies that offered the solution in the oil and gas fields and provided it as a service.

3) Compact LNG plants , offering the same as 2) for easy onsite or near site within a play /field region for gas to LNG and further transport by LNG trucks to points of storage/transport or regasification

 

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14 hours ago, ceo_energemsier said:

I mentioned some where else on this forum recently and last year about the various options for produced gas before pipelines and processing/gathering facilities are in place to prevent the flaring.

1) Produced gas reinjection into the formation or into another zone for later use and or increasing liquid hydrocarbons production volume. We tried that in several different parts of the country and different countries and it worked well. Saved a valuable resource for future use and also prevented the air quality issues etc.

2) Compact GTL plants that would convert the gas to liquids fuels . There are several companies that offered the solution in the oil and gas fields and provided it as a service.

3) Compact LNG plants , offering the same as 2) for easy onsite or near site within a play /field region for gas to LNG and further transport by LNG trucks to points of storage/transport or regasification

 

The so called environmentalists should be working on this practical approach rather than fighting fracking which has become a turbocharger for the American economy and will eventually be used wherever indicated.

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EIA forecasts US shale output to keep rising until peak after 2030
by Staff Writers
Washington DC (UPI) Apr 03, 2019

Production of the so-called shale, or tight oil, will continue to increase through 2030 and reach more than 10 million barrels per day in the early 2030s, the Energy Information Administration said.

"EIA projects further U.S. tight oil production growth as the industry continues to improve drilling efficiencies and reduce costs, which makes developing tight oil resources less sensitive to oil prices than in the past," according to the EIA's Annual Energy Outlook 2019.

Tight oil, or shale oil, production refers to extraction of crude oil contained in low-permeability formations that, thanks to technological advances, started to be tapped resulting in soaring production in the United States and becoming in 2015 the more common form of oil production.

Shale oil production reached 6.5 million barrels per day in the United States in 2018, accounting for 61% of total U.S. production.

Most of the increase in recent years in crude oil production in the United States is related to the development of the Permian Basin in western Texas and eastern New Mexico.

"Three major tight oil plays in the Permian Basin - the Spraberry, Bone Spring, and Wolfcamp - accounted for 41 percent of U.S. tight oil production in 2018," and they will remain very important in coming decades potentially representing half of the cumulative tight oil production in the next 30 years, the EIA said.

Bakken and Eagle Ford also remain major contributors to U.S. tight oil, and accounted for 19 percent and 17 percent of crude oil production in 2018. Eagle Ford is in Texas, while the Bakken occupies parts of Montana, North Dakota and Canada.

"Future growth of domestic tight oil production depends on a variety of factors, including the quality of resources, technology and operational improvements that increase productivity and reduce costs, and market prices," the EIA said.

The EIA worked on two alternative cases in which technology and resource assumptions are modified. In one optimistic technology, lower-cost scenario, total U.S. oil production in 2050 is nearly 19 million barrels per day.

In the less optimistic scenario total U.S. oil production in 2050 falls to about 8 million barrels per day, it said.

The EIA also contemplated the impact that international oil prices could have, and evaluated scenarios contemplating a high as well as a low oil price.

In the high oil price scenario, in which oil hits $100 per barrel in 2019 and rises to $208 (in 2018 dollars), that would lead to a peak of 18 million barrels per day by 2024 before declining to 13 million barrels per day in 2050.

EIA reports that conventional oil production in the United States during the period covered appears relatively steady at 4 million barrels per day for nearly all of the period.

In the low oil price case scenario, which contemplates an average price under $50 per barrel through 2050, total domestic production would increase to nearly 13 million barrels per day in 2022, before declining through the rest of the period.

According to the American Fuel and Petrochemical Manufacturers, hydraulic fracturing has been utilized for more than 60 years and has been "safely and effectively applied" to well over a million oil and gas wells in the United States alone.

Hydraulic fracking, which injects water mixed with chemicals to penetrate shale formations, is controversial. There are more than 700 studies that have focused on potential risks, with a high number of them showing risks or actual harms, Forbes reported.

New York, Vermont and Maryland, which has proven gas reserves, have laws banning fracking.

Source: United Press International

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About shale tech:

Every little innovation, improve matters and counts towards a drop in costs, increased efficiency and production in addition to sustainability.

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Dow recognized for resin-coated proppant helpful to shale oil

A special proppant designed by Dow for the shale oil and gas industry helped the Michigan chemical giant earn a prestigious Edison award. The awards are given every year to honor excellence in innovation. Dow’s trademarked VORARAD downhole sequestration technology earned a silver award.

According to Dow, the resin-coated proppant can inhibit harmful isotopes, like radium, from rising to the surface, which aides in minimizing the amount of naturally occurring radioactive material that is brought to the surface during flowback production.

The coated sand is able to trap Radium particles downhole and also create a stronger network of frack matrices by limiting the amount of sand that can travel back to the surface after pressure

pumping is complete and a well is on production.

Dow’s lab tests on the material show that it can reduce Radium in isotopes of water by as much as 65 percent.

The ability of the resin-coated sand to stay secure downhole also helps to reduce pipe and pump blockage.

In addition to the resin-coated sand product created for the unconventional oil and gas industry, Dow was also recognized for work creating better photovoltaic elastomers, packaging material, ecofriendly coloring for cottons, and heat-resistant packaging.

Being recognized with an Edison Award has become one of the highest accolades a company can receive in the name of innovation and business, the awarding entity explained. “The awards are named after Thomas Alva Edison (1847 to 1931) whose inventions, new product development methods and innovative achievements that changed the world, garnered him 1,093 U.S. patents and made him a household name around the world.”

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‘Really Smart Guys’ Push to Make Biggest Oilfield Even Bigger"

 

From Bloomberg

Standing at the center of the prolific Permian Basin, Scott Hodges explains how the future of the world’s largest oil field may very well depend on what he calls jokingly calls the “really smart guys.”

Hodges, a 57-year-old manager with Occidental Petroleum Corp., runs a cluster of installations at the Hobbs oil field, where dozens of wells don’t pump a single barrel of oil but instead do the opposite: push stuff — lots of it — into the ground.

Occidental runs the operation in southeast New Mexico as part of its so-called enhanced-oil-recovery program, injecting carbon dioxide and water underground to force out crude that might otherwise languish in the reservoir. EOR already works in conventional oil fields — now the company is trying to make it work commercially in shale rock.

If Occidental and its rivals’ experiments with similar techniques are successful — a big if, in the view of many others — it could further transform the Permian, which is already the world’s largest oil patch. To do that, knowing how the oil, gas, CO2 and water work together thousands of feet below the Earth’s surface is crucial.

“The guys who know what’s happening underground is the RSG,” Hodges says in reference to the company’s Reservoir Study Group. “That stands for the really smart guys,” he adds, laughing.

While the U.S. shale revolution has boosted American oil production to a record, it’s also leaving lots of crude in the ground. At best, fracked wells only recover about a 10th of what the industry calls the oil-in-place.

“We are trying to be very conservative, but certainly we believe that we can improve from 10-11 percent to 17-18 percent,” Occidental Chief Executive Officer Vicki Hollub said in an interview in Houston. “It’s a lot. When you consider the scale of the Permian basin, to do that will be amazing.”

Hobbs is a conventional Permian field, developed decades before engineers figured out how to drill horizontally and then inject huge amounts of water, sand and chemicals to open up fractures in the rock, freeing hydrocarbons from shale reservoirs.

Across the U.S., there are over 80,000 shale oil and gas wells more than five years old, pumping a trickle of hydrocarbons. They provide a massive opportunity for anyone who can figure out how to extend their life and extract a few extra barrels. Achieving that would be especially welcome in the shale industry, which is currently compelled to invest more each year in new production just to offset the natural decline of its older wells.

“The wells are there, and the upside is free,” said Raoul LeBlanc, an oil expert at consultant IHS Markit Ltd. and a former head of strategy at Anadarko Petroleum Corp. “If anyone can figure out how to achieve another 5 percent extra, that’s the golden ticket.”

The challenges are daunting, however. In conventional rock, EOR engineers inject CO2 and water via one well, flooding the reservoir and pushing the oil and gas out of another well. It’s a lot more difficult for shale. For a start, the temperature and pressure need to be just right for the CO2 to mix with the oil. Furthermore, the CO2 and water struggle to move through the tightly packed rock. While Occidental is testing the conventional method of different wells for shale, it’s also piloting a different technique that uses one well for both injection and production.

Occidental isn’t alone. Chevron Corp., which is expanding fast in the Permian, has lots of experience with EOR outside of shale, particularly in mature fields in California. EOG Resources Inc., the largest independent shale producer, is experimenting with the injection of natural gas.

Globally, the International Energy Agency estimates there are more than 166 EOR projects using CO2, producing about 450,000 barrels of oil a day. By 2040, it anticipates output from similar projects will almost quadruple to 1.64 million barrels. The method also has the advantage of potentially sequestering the gas and helping the fight against climate change.

“There’s a great appetite for EOR, because it’s good to the financial aspect but also the environmental aspect,” Fatih Birol, the head of the International Energy Agency, said in an interview.

If the technology works in shale, Occidental and its rivals will still need to figure out how to make it economic. In conventional Permian fields, CO2 injection could add another $6 per barrel to the cost of extracting the crude. With West Texas Intermediate trading at around $60 a barrel, that’s a significant add-on, especially as drillers have come under more pressure to improve returns to investors. However, the U.S. government is providing some help with tax credits to oil producers who store CO2.

Occidental has told investors it hopes to declare EOR viable later this year and give its first commercial project the go-ahead in 2020. Hollub is confident it already works.

“The pilot wells deliver more than what our model indicated they would, so it’s a success,” she said. “Now we have to determine how to build the infrastructure. You need scale to make it work.”

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My 2 cents:

 

EOR for shale wells is the next big tech that will reignite and reinvigorate the industry and will bring forth more production at lower costs. The only thing standing between that is time , there are dozens and dozens of companies (if not more) that are working diligently on tis.

Personally we have tested some combination of  technologies in the Bakken, Eagle Ford and Marcellus that have been giving us extremely positive and viable results.

We have also used several different technologies and combination of suites of technologies in conventional oil and gas that have resulted in extremely positive results in improved production and long term sustainability as well as increase in proved reserves.

 

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Permian gas pipeline could ease bottlenecks, give global access

For $3.7 billion, Permian Global Access Pipeline LLC intends to build a shale gas pipeline that would connect the Permian shale play to Lake Charles, Louisiana. The shale gas would be utilized by Tellurian Inc., a publicly traded natural gas entity looking to source natural gas from the U.S. for export across the globe.

An open season call on the pipeline has been started. If completed, the pipeline will use a 42-inch diameter line to move roughly two billion cubic feet per day of natural gas. For Tellurian, the pipeline is only part of a larger infrastructure buildout plan. In total, Tellurian wants to invest $7.3 billion in U.S. infrastructure in addition to another $15.2 billion on a liquified natural gas export facility in Lake Charles.

The Permian is currently one of the top shale gas producing regions in the world. Meg Gentle, CEO, said producers there have had to pay $9.00/mmBtu just to move their gas from the region to outside markets.

The proposed pipeline would originate in Pecos County, Texas. Construction could be finished by

2023.

The U.S. currently has one LNG export facility located in Louisiana. By 2021, the U.S. Energy Information Administration believes the country will house five LNG export facilities capable of exporting 9.2 bcf/d.

According to April data from the EIA, the Permian is producing more than 14 mcf/d of shale gas.

Gentle said in addition to helping Permian producers, some of the natural gas sourced from West Texas could be used in Louisiana.

“Southwest Louisiana is a market expected to grow 300 percent in the next five years,” she said. “The Permian Global Access Pipeline is critical infrastructure that will interconnect stranded Permian gas production with growing markets, reduce flaring, and provide a valuable cleaner fuel to reduce urban pollution and carbon globally.”

Earlier this year, Tellurian also signed a long-term offtake deal with India for LNG sourced from the U.S.

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(edited)

On 4/1/2019 at 5:57 AM, Old-Ruffneck said:

I worked long enough and have a good insight as what price point is decent and don't need Mike Shellman to tell me his opinion on pricing. He isn't in the Frackin' business and when I  spent 2 month just recently in West Texas where the drilling is at, I inquired with Company Men and drillers and even Floor Hands. The cost are now Break-even 20 bux to 25 bux outta the hole. And in some cases less. Some more. It doesn't take that much to move it refine it to an overall cost of 35bbl. So reasoning 20 per bbl is a decent profit. Get greedy as I said before and the whole market goes to hell. Its effect on the whole economy causing inflation is good? 

I’m sorry, since when do Company Men or Rig Hands have inside information on break-evens?

Unless any of them have a WI, you’d just as well ask the Easter Bunny

Edited by Ian Austin

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14 minutes ago, Ian Austin said:

I’m sorry, since when do Company Men or Rig Hands have inside information on break-evens?

Unless any any of them have a WI, you’d just as well ask the Easter Bunny

Well, guess the Easter Bunny is smart, figured out its not really inside information. Those that work in their field sometimes actually know a little about what actual costs are. So don't be sorry if you don't know. 

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(edited)

4 minutes ago, Old-Ruffneck said:

Well, guess the Easter Bunny is smart, figured out its not really inside information. Those that work in their field sometimes actually know a little about what actual costs are. So don't be sorry if you don't know. 

Ok Mr. Ruffneck. I’ll trust the Res Engineers, or people who track these wells through its lifecycle, over your friends.

And I know quite a bit about the economics of Producing Oil and Gas thank you very much. 

Edited by Ian Austin

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5 minutes ago, Ian Austin said:

Ok Mr. Ruffneck. I’ll trust the Res Engineers, or people who track these wells through its lifecycle, over your friends.

And I know quite a bit about the economics of Producing Oil and Gas thank you very much.

Exxon and Chevron have already posted break-evens on some of the new wells around Coyanosa  and Pecos sites. The economics of 2 years ago don't apply in todays drilling technics. Much lower now, and getting even lower. But you stated you know the economics quite a bit so I guess your in the business, and have other information that proves otherwise.

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5 minutes ago, Old-Ruffneck said:

Exxon and Chevron have already posted break-evens on some of the new wells around Coyanosa  and Pecos sites. The economics of 2 years ago don't apply in todays drilling technics. Much lower now, and getting even lower. But you stated you know the economics quite a bit so I guess your in the business, and have other information that proves otherwise.

I would be inclined to believe that, over time, CVX and XOM will make some money (or at least won’t lose any) in a Shale - they studied it to death before jumping in, won’t need to borrow from every conceivable corner of the market, and own every piece of the supply chain. 

However, I’d dispute any breakeven proclamation made his early in the game (how much/how long have said wells been producing? Are the lifecycle costs generic?). I’ve sat in many a Reserve booking meeting and you’d be shocked at how little work is put into understanding this stuff (almost everything is booked with a very “generous” estimate of EUR). Do they know how many Workovers/Recompletions are going to be required throughout the life (I can count at least 3-4 off the top of my head - here’s an extra 1-1.5MM, best case)? There are so many unknowns that anybody who spits breakeven costs after 6-12 months producing is, how would I say it kindly, completely full of s$$t. 

On the Drilling Technology side of the business, one I spent 15+ years in (and actually have worked as a Technology Advisor for a couple of the large US E&Ps)  there’s actually precious little new tech - a lot of changes to methodology, some better PDC cutters (to handle increased abuse. The same could be said about the various upgrades to MWD suites), some strides made with motor power outputs, and some nice tweaks to Rig designs to allow for automation and taking certain tasks off critical path. None is new - it’s all existed in the offshore industry for quite a while. 

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50 minutes ago, Ian Austin said:

And I know quite a bit about the economics of Producing Oil and Gas thank you very much

^ True that bit.  Ian is definitely no greenhorn.

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The Return Of The Bakken

Wed, 04/10/2019 - 11:00

Fifteen miles west of New Town, N.D., along state Highway 23 and turning north about 7 miles toward the foot of the Antelope Creek State Wildlife Management Area, Continental Resources Inc. completed 13 wells at its Tarentaise Federal pad in the fall of 2017, in McKenzie County. Combined, the wells have produced more than 3.1 million barrels (MMbbl) of oil through this past January.

In Dunn County, the Mountain Gap pad, 31 miles south of Mandaree on Bureau of Indian Affairs Road 12 and 5 miles west on Gap Road, 10 wells were completed in the spring of 2018. Through this past January, the drilling-spacing unit (DSU) had produced 1.8 MMbbl.

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On ‎4‎/‎9‎/‎2019 at 8:29 PM, Ian Austin said:

I would be inclined to believe that, over time, CVX and XOM will make some money (or at least won’t lose any) in a Shale - they studied it to death before jumping in, won’t need to borrow from every conceivable corner of the market, and own every piece of the supply chain. 

Ya think they might make some money?? or at least break even?? Your ignorance is getting ahead of you. You go sit at your desk and stare at your screen. CVX is already making good money in the Delaware Basin. XOM just getting there. Betting against the Permian at this point is not good decision making for a 15 yr analyst. See, even engineers are wrong more than they are correct. In the not so distant future (2yrs), ramping up production to fill all the lines running out of the Permian tells me someone didn't let you in on their meeting. Not rocket science to get 6mmb out and in the pipes. Eventually a lot of the wells will need refracked, but that is already figured and accounted for. Not all sands are equal and using local medium is low grade and eventually will plug the seeps. Trying to save money now but quality sand on a 3 to 4k lateral is better than the crap their digging locally for the 15 to 20k laterals. Inferior product will plug the well. Just wait.

 

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(edited)

55 minutes ago, Old-Ruffneck said:

Ya think they might make some money?? or at least break even?? Your ignorance is getting ahead of you. You go sit at your desk and stare at your screen. CVX is already making good money in the Delaware Basin. XOM just getting there. Betting against the Permian at this point is not good decision making for a 15 yr analyst. See, even engineers are wrong more than they are correct. In the not so distant future (2yrs), ramping up production to fill all the lines running out of the Permian tells me someone didn't let you in on their meeting. Not rocket science to get 6mmb out and in the pipes. Eventually a lot of the wells will need refracked, but that is already figured and accounted for. Not all sands are equal and using local medium is low grade and eventually will plug the seeps. Trying to save money now but quality sand on a 3 to 4k lateral is better than the crap their digging locally for the 15 to 20k laterals. Inferior product will plug the well. Just wait.

 

Ok, I don’t see the need to continue this - we will call it a day. 

By the way, have you actually done anything in the industry, or is our knowledge limited to “talking to friends”?

Edited by Ian Austin
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6 hours ago, Ian Austin said:

Ok, I don’t see the need to continue this - we will call it a day. 

By the way, have you actually done anything in the industry, or is our knowledge limited to “talking to friends”?

Well geez, I did work a couple days roughnecking on a couple rigs. Just a couple though so I am no "expert". 78 through 85 and left when Reaganomics killed the industry. I normally try not to be a smarta** but when you jumped in and made your first comment I felt disrespected and you kept on. Typed words can't tell the tone of ones thoughts. I took your remarks as flippant. Maybe that wasn't your intention, but as dumb ol' ruffneck I sometimes have no control over what my fingers are typing in responses. No harm no foul friend. I will be civil from now on. My apologies, k?

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@Ian Austin and @Old-Ruffneck no worries, just some verbal differences.  Nothing to get upset about.  Both of you have your own unique experiences in the oil patch.  Oil experience is not the target here, but how about them there Oil Hates club over yonder, they could prolly use a good browbeating for p*ssing in the oil patch and stopping oil pipelines.

Up to you...

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1 hour ago, Old-Ruffneck said:

Well geez, I did work a couple days roughnecking on a couple rigs. Just a couple though so I am no "expert". 78 through 85 and left when Reaganomics killed the industry. I normally try not to be a smarta** but when you jumped in and made your first comment I felt disrespected and you kept on. Typed words can't tell the tone of ones thoughts. I took your remarks as flippant. Maybe that wasn't your intention, but as dumb ol' ruffneck I sometimes have no control over what my fingers are typing in responses. No harm no foul friend. I will be civil from now on. My apologies, k?

Apologies, the comments were meant with the best of intentions. I tend to be skeptical of a lot of things, mainly because of some of the garbage I’ve seen pulled from the inside (I’m definitely not Yota, but could down quite a few beers telling stories about things being manipulated economically). 

No harm no foul. We both probably got a little “misunderstood”. I apologize as well

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Deal to acquire Anadarko positions Chevron as Permian leader

HOUSTON, Apr. 12
04/12/2019

Chevron Corp. has agreed to buy Anadarko Petroleum Corp. in a cash and stock deal that values Anadarko at $50 billion and creates growth opportunities for Chevron in areas that play to its operational strengths.

“The combination of Anadarko’s premier, high-quality assets with our advantaged portfolio strengthens our leading position in the Permian, builds on our deepwater Gulf of Mexico capabilities, and will grow our LNG business,” said Michael With, Chevron chairman and chief executive officer.

In 2018’s fourth quarter, Anadarko produced 691,000 boe/d (nearly 60% oil) from the Denver-Julesburg (DJ) basin (40%), the Permian basin (20%), and the Gulf of Mexico (20%), Cowen analysts said in a research note Apr. 11.

Upon close, Chevron would become the second-largest producing major in 2019 terms from its current position at number four, according to Wood Mackenzie analysts, and puts ExxonMobil, Chevron, Shell, and BP “in a league of their own,” said Roy Martin, Wood Mackenzie senior analyst, corporate analysis.

The new entity would move ahead of Shell and BP in terms of oil and gas production, trailing only ExxonMobil and the five biggest national oil companies in terms of the world’s largest producers of oil and gas, according to Rystad Energy.

Tight oil

As of Feb. 5, Anadarko was operating 14 drilling rigs in the US onshore, with 9 in the Delaware basin, 4 in the DJ basin, and one in the Powder River basin.

Anadarko is the largest producer in Colorado’s DJ basin, where its 400,000 net acres are estimated to hold more than 2 billion boe of recoverable resources. In the Permian’s Delaware basin, Anadarko holds nearly 600,000 gross acres and 8,500 ft of stacked oil potential. The combination of the two companies will create a 75-mile-wide corridor across Delaware basin acreage.

“By buying Anadarko, they take on a highly contiguous Delaware basin position in the Permian. Chevron ought to be able to do more with the acreage than Anadarko, which lagged behind in terms of well productivity,” WoodMac's Martin said.

“We have always considered Anadarko as having the best positioned acreage in the sweetest spot of the Permian Delaware basin,” commented Per Magnus Nysveen, Rystad Energy founding partner and head of research. The combination of Anadarko’s Permian assets with Chevron’s positions the company to emerge “the clear leader among all Permian players, both in terms of production growth and as a cost leader,” he said.

“By 2025 the merged entity will be able to produce as much 1.6 million b/d of oil from the Permian basin alone,” Nysveen said.

Chevron expects the combine to enhance its existing position in the deepwater Gulf of Mexico and extend its deepwater infrastructure network. Anadarko is a large leaseholder and producer in the deepwater gulf, with infrastructure that includes 10 operated deepwater facilities. The company’s newest spar facilities, Lucius and Heidelberg, began production respectively in January 2015 and January 2016.

Chevron would gain a resource base in Mozambique to support growing LNG demand. Anadarko is a 26.5% owner and operator of Mozambique LNG, a 12.88 million-tonne/year LNG project expected to take final investment decision in the first half of this year. Plans for the onshore consists of two initial LNG trains to support Golfinho-Atum field, which lies entirely within Offshore Area 1, where the company and its partners have discovered 75 tcf of recoverable natural gas resources.

With the deal, Chevron gains access to Western Midstream Partners LP.

“Chevron has been noticeably absent in the midstream rush of the past couple of years. It now takes a 55% stake in Western Gas, which goes a long way toward fixing that,” said RT Dukes, WoodMac research director, Lower 48 oil and gas. The structure was simplified last year, “giving Chevron a vehicle to spin assets down in the future if needed,” Dukes said.

Transaction details

The 25% cash, 75% stock deal values Anadarko at $50 billion. The offer is priced at $65/share, representing a 39% premium over Anadarko’s close on Apr. 11. In aggregate, upon closing, Chevron will issue some 200 million shares of stock and pay about $8 billion in cash. Chevron will also assume estimated net debt of $15 billion.

The transaction is expected to generate annual run-rate synergies of $2 billion and will be accretive to free cash flow and earnings one year after close, said Michael Wirth, Chevron chairman and chief executive officer.

Using the deal size as a marker, RBC analyst Scott Hanold sees synergies moving upward to $4-5 billion “as the portfolios get rationalized and priorities are clarified,” subject to “the success of Chevron’s asset sales program, which has now been upgraded from $5-10 billion over 2018-20, to $15-20 billion over 2020-22.

“Looking through the lens of assets with limited growth potential,” he said, Chevron could divest assets in Canada, Colombia, Azerbaijan, and select parts of its Asian portfolio.

The transaction, approved by both companies’ boards, is expected to close in the second half of this year, subject to Anadarko shareholder approval, regulatory approvals, and other customary closing conditions.

Upon closing, the combine will be led by Michael Wirth as chairman and chief executive officer and remain headquartered in San Ramon, Calif.

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Argus launches new crude price reflecting shifting Permian crude quality

Houston, 10 April 2019

Global energy and commodity price reporting agency Argus today launches a new light crude price assessment to reflect growing light oil production in the Permian basin of west Texas and New Mexico. The new West Texas Light (WTL) price, published daily in the Argus Crude report, is for Permian basin crude with a gravity of 44.1-49.9°API traded at terminals in Midland, Texas.

Midland is the chief gathering hub for Permian basin crude, the fastest growing source of oil in the world. An increasing share of Permian crude is lighter than 44°API, and midstream companies have created the WTL stream to separate lighter crude from the denser main Permian WTI grade, which is typically at 40-44°API.

Much WTL trade is taking place at differentials to Argus’ benchmark WTI Midland price, which is assessed at terminals in Midland, Texas. Argus will publish its new WTL price assessment as a differential to WTI Cushing as well as an outright number.

WTL has also begun to trade at Houston at a differential to the benchmark Argus WTI Houston price, which is widely used to price US exports. Argus WTI Houston, which is assessed at Magellan’s MEH terminal, is also the settlement price for derivatives contracts on the Ice and CME exchanges, where open interest currently stands at 200mn bl with daily trading volumes topping 10mn bl. Argus intends to publish a separate WTL Houston index as volumes grow.

"Argus welcomes the opportunity to provide greater transparency to the market for Permian crude as production continues to grow and as more of the output is lighter than traditional WTI,” Argus Media chairman and chief executive Adrian Binks said. “Argus WTI Houston and Argus WTI Midland are two of the most liquid and transparent physical spot crude price indexes in the world. We expect to see the liquidity of the WTL market at Midland and later at Houston grow rapidly as well.”

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Concho Resources Forms Permian Midstream JV To Support Midland Basin Growth

Concho Resources agreed to form a JV with Frontier Midstream Solutions, which will build and provide crude oil gathering, transportation and storage services in the Northern Midland Basin.

Concho Resources Inc. formed a midstream joint venture (JV) on April 15 to support its continued oil production growth in the Midland Basin region of the Permian.

The Midland, Texas-based shale producer said it agreed to form Beta Crude Connector LLC (BCC) through a JV with Frontier Midstream Solutions IV LLC. BCC will build and provide crude oil gathering, transportation and storage services in the Northern Midland Basin.

Concho and Frontier will each own a 50% equity interest in BCC, with Frontier serving as operator.

The new gathering and transportation system will consist of a roughly 100-mile gathering system, 250,000 barrels of crude oil storage facilities as well as truck terminals. The pipeline system will have the initial capacity to deliver 150,000 barrels per day of crude oil to multiple delivery points, accessing local refineries and connecting to several downstream pipelines, according to a joint press release.

Concho’s planned activity for 2019 is expected to deliver oil growth of 26% to 30% across its roughly 640,000 net acres in the Permian Basin. In the Midland Basin, the company has about 260,000 gross acres.

Jack Harper, president of Concho, commented, “Through the joint venture, we will leverage Frontier’s midstream expertise and enhance the value of our high-quality footprint in the Midland Basin with a reliable, cost-efficient gathering and transportation solution. Importantly, this is a compelling investment opportunity that we can make with no changes to our capital plans.”

Currently, Concho plans to spend between $2.8 billion and $3 billion in 2019, which represents a 17% reduction from the company’s prior capital guidance.

In conjunction with the JV agreement, Concho also agreed to enter into a long-term acreage dedication agreement with BCC.

Following an open season set for April, construction on BCC will commence, targeting initial flows in mid-2019.

BCC will file for FERC authority to operate as a common carrier pipeline and solicit interest from other producers and marketers for capacity on the new system.

Frontier Midstream Solutions, headquartered in Tulsa, Okla., is owned by Frontier Energy Partners II LLC and certain funds of Energy Spectrum Capital. 

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