AuthorTopic: Hills Group Oil Depletion Economic and Thermodynamic Report  (Read 44558 times)

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🛢️ A New Trend In Natural Gas: Just-In-Time Supply
« Reply #210 on: March 25, 2019, 01:39:03 AM »

A New Trend In Natural Gas: Just-In-Time Supply

A New Trend In Natural Gas: Just-In-Time Supply

U.S. natural gas prices reached the highest maximum level in 4 years this winter. That’s because of a new “just-in-time” gas supply paradigm that relies more on wellhead production than storage. It has pluses and minuses.

In November 2019, weekly Henry Hub spot prices were $4.68/mmBtu, a level only exceeded in January 2014 over the last several years (Figure 1).

(Click to enlarge)

Figure 1. Highest natural gas price maximum in four years.
Source: EIA and Labyrinth Consulting Services, Inc.

That was because winter gas storage was the lowest since then (red fill in Figure 1).

Record gas production and expansion of northeastern pipeline systems led to a new just-in-time natural gas supply paradigm. Dry gas production set a new record high of 88.7 bcf/d in February (Figure 2). Gas output increased an astonishing 17.7 bcf/d from January 2017 and the present

(Click to enlarge)

Figure 2. Record 88.77 billion cubic feet per day dry gas production in February 2019.
Source: EIA STEO and Labyrinth Consulting Services, Inc.

That and new pipeline take-away capacity from the Marcellus and Utica plays led markets to believe that supply was almost infinite."

Gas futures forward curves reflected the new just-in-time paradigm. Before 2017, the “normal” term structure of gas forward curves reflected generally higher future than spot prices. This contango structure included higher frequency seasonal use variations in pricing (Figure 3).

(Click to enlarge)

Figure 3. Term structure of Henry Hub forward curves changed after 2017 from “normal” to “inverted-normal.”
Source: CME and Labyrinth Consulting Services, Inc.

Beginning in about 2017, the term structure for shorter-dated contracts inverted and then, reverted to the normal pattern. This discouraged storage in the short term and resulted in record low inventory volumes going into the winter heating seasons of 2017-18 and 2018-19. Related: Oil Is Set To Rise, But The Rally May Not Last

Although production is at record levels, so are U.S. gas exports. February net imports were -4.52 bcf/d and net imports are expected to reach almost -8 bcf/d by November 2019 (Figure 4).

(Click to enlarge)

Figure 4. February U.S. net natural gas imports were -4.52 billion cubic feet per day.
Source: EIA STEO and Labyrinth Consulting Services, Inc.

Markets may not have fully comprehended that production and supply are not the same thing. Exports reduce the amount of gas available for domestic consumption.

The new gas supply paradigm has led to lower levels of gas-in-storage than in previous years. This in turn exposed markets to higher short-term prices during cold periods this winter.

Many believe that higher prices resulted from a cold winter and that this will not be repeated during more normal winters. That is untrue. So far, this winter has been 3 percent warmer than the norm. Gas price spikes occur when storage is low. Cold weather is an accelerant for price spikes, not their cause.

Just-in-time gas supply is here to stay as long as shale gas and tight oil companies continue to over-produce natural gas. That will lead to lower prices on average. That’s a plus for consumers. We should, however, expect greater price volatility when weather and low storage combine to produce temporary tight supply. That’s a minus.

This winter’s pricing should be a reasonable model for next winter. Let’s see what surprises just-in-time supply provides this summer!

By Art Berman for


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🛢️ Big Oil Is Heading Offshore
« Reply #211 on: April 01, 2019, 05:19:38 AM »

Big Oil Is Heading Offshore
By Irina Slav - Mar 31, 2019, 5:00 PM CDT

Oil companies will this year increase their investments in offshore drilling for the first time after five years of spending cuts as optimism for this segment of the industry returns and the spotlight shifts away from shale.

Bloomberg quotes industry executives attending the Scotia Howard Weil Energy Conference in Louisiana this week as saying the recovery in offshore drilling was already underway and not somewhere in the future. A big part of the reason is that offshore drilling in some parts of the world is now cheaper than drilling in the Permian.

Hess Corp’s chief executive John Hess must have raised some shale-loving eyebrows at the conference when he compared the production costs of the Permian and its own Liza project offshore Guyana. To pump the equivalent of 120,000 bpd, Hess said, you’d need to spend US$12.8 billion in the Permian versus US$3.7 billion in Guyana. While this stark difference is not universal across offshore prospects and fields, it certainly gives investors some food for thought.

The offshore recovery is a sign of returning optimism for the long-term prospects of the industry as well. What fueled the first shale revolution was the fact that oil began flowing so much faster from fracked wells as compared with offshore ones: months versus years. Yet fracked wells also have shorter productive lives than offshore wells, and now investors seem to be beginning to remember this.

Interestingly enough, it’s not just untapped prospects that are drawing attention. The Gulf of Mexico—and the North Sea as well—are also places of interest for oil and gas companies.

“Investors are thinking about being basin-agnostic again, and that at least gives us the opportunity to reintroduce the Gulf of Mexico,” the chief executive of Talos Energy told Bloomberg on the sidelines of the event. “It’s allowing investors to just rethink under a new lens how they view offshore, and we have to take advantage of that opportunity.”

Meanwhile, shale operators are tightening the strings of their purses again, with the few notable exceptions being Big Oil majors. Pressured by investors to bring in higher returns rather than more barrels of crude, independents are reducing their exploration spending in the shale patch. As a result, related projects are being shelved.

Reuters reported earlier this week Magellan Midstream Partners had canceled its Permian Gulf Coast pipeline project that would have added 1 million bpd to pipeline capacity in the region. This capacity is necessary at the moment, but the Permian Gulf Coast pipeline would have only begun operating in the middle of next year when the additional capacity may not be needed as exploration investment shrinks.

This seems like a sharp change of pace in the shale patch after months of complaints about a shortage of pipeline capacity amid growing production and forecasts that this production growth will continue. Apparently, the forecasts did not take into account shareholder priorities, which are invariably topped by returns.

With the shale space already crowded and not as cheap as it was once, it makes sense that oil companies are looking offshore especially as the number of tenders in that space picks up as well and there are more opportunities to choose from. This pick-up in oil tenders for offshore deposits is evident across the globe, in legacy areas such as the Gulf Coast and Brazil but also in oil and gas hopefuls such as Guyana, which is turning into a hot spot as Hess and its partner in the Stabroek block make discovery after discovery. Offshore drilling is definitely coming out of the shadows of spending cuts.

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Dutch Supreme Court = Royal Dutch Shell.


Business News
April 15, 2019 / 9:44 PM / Updated 3 hours ago
Chevron says Dutch Supreme Court rejects Ecuador's $9.5 billion claim

(Reuters) - The Supreme Court of the Netherlands dismissed Ecuador’s attempts to annul decisions of an international arbitral tribunal that ordered Ecuador to prevent enforcement of a $9.5 billion judgment against Chevron Corp anywhere in the world, the U.S. oil major said on Tuesday.

Chevron said the Dutch court’s decision upholds rulings of two Dutch lower courts which rejected Ecuador’s attempts to annul those awards.

“The Dutch supreme court found that the challenged arbitral awards are consistent with public policy and justified to prevent irreversible harm to Chevron,” the company said.

Earlier this month, the Supreme Court of Canada had dismissed claims attempting to force Chevron’s Canadian unit to pay the $9.5 billion judgment handed down in Ecuador against the company over pollution in the Andean country.


Residents of Ecuador’s Lago Agrio region have been trying to force Chevron to pay for water and soil contamination caused from 1964 to 1992 by Texaco, which Chevron acquired in 2001.

The villagers obtained a judgment against Chevron in Ecuador in 2011.

The latest decision adds to several court victories that Chevron has won against the plaintiffs and its legal team in this case.

Reporting by Philip George and Kanishka Singh in Bengaluru; Editing by Gopakumar Warrier

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🛢️ Could This Be The Next High Profile Permian Takeover?
« Reply #213 on: April 17, 2019, 01:19:47 AM »

Could This Be The Next High Profile Permian Takeover?

By David Messler - Apr 16, 2019, 4:00 PM CDT

Chevron put the Oilfield M&A game in motion on Friday, with their announcement of a cash and stock offer for Anadarko Petroleum. The oil industry is ripe for some M&A activity, as the nice premium of about twenty percent that was offered to the prior closing price, seems to indicate.

I think a case can be made for exceptionally well-rounded oil companies to be high on the lists of potential acquisitors in the hunt for value. One such company is Apache Corporation. In this article we will take a look at to why I think they could be the next domino to fall.

The general thesis for upward movement in oil equities

Oil equities are under-valued at present by thirty or forty percent, taking the recent performance of the XOP index as an example, in relation to the price of oil. From the Dec. 24th, 2018 low, the XOP has regained about 30% of its pre-crash level, while oil has nearly doubled. Anadarko makes up about 2% of the XOP.


Over the past year we have seen valuations decline anywhere from 25-40%. The market typically over or under reacts with equities tied to commodities in particular. When the underlying commodity loses value as oil did in the fourth quarter of 2018, shares can fall precipitously. The three month period ending December, 24th 2018 is reflective of this condition.

We have seen a sharp "V" shaped recovery since, as was expected. One of my favorite expressions from tenth grade geometry still rings true, “The angle of incidence equals the angle of reflection.” It’s been a strong recovery, but we have still have not regained the highs of Q-3, 2018. Friday's action by Chevron could be an inflection point for multiple expansion in oil equities.

A More Favorable Environment For Oil Prices

In the first quarter of this year the winds shifted and many of the factors that had been dragging oil lower, reversed themselves. Among them we can count:

• The Fed tapping the brakes on the tightening policy of the last couple of years.
• The repeated declaration of the Saudis to raise global pricing, through declining exports to the U.S.
• The chaos in Venezuela and imminent (eternal) civil war in Libya are providing concerns about supply.
• Some signs that shale drillers are taking a drilling pause to let prices improve a bit.
• Signs that shale productivity may be leveling off, i.e. more inputs being required to maintain current levels.
• The generally positive comments coming out of the China trade talks.

There is no cause and effect relationship necessarily between oil and the stocks of the companies that extract it. There have been a lot of factors weighing on the market, and they are the reasons for the current disparity between oil and oil stocks. What is needed to help close the gap, is an inflection point that signals a shift in the market's thinking.
Related: Think Tank: Mexico’s New Refinery Already Doomed

Chevron might have just delivered this inflection point last Friday.

What changes things for North American shale post the Chevron/Anadarko tie-up?

We have been inundated with theories about shale peak-ing out in recent times. You've may have read them... the ones by Martenson and Berman stand out in particular. In this one, and in others very cogent arguments have been made, that growth trajectory of shale plays is in decline due to poorer rock quality than in the past. Some, like Jim Chanos posit a very dark interpretation of shale results so far, that's it all been a hoax. The words "Ponzi Scheme" are used frequently by the doom sayers.

It is not my intention to challenge any of these pundits squarely today. They may very well be right, time will tell. What I do want to address in this article is an element of market activity being ignored by the "doom crowd." The clever arguments put forward for shale slipping (crashing?) into decline, have managed to ignore one simple fact.

The shale-doom crowd chooses to ignore the obvious, and frankly, the most compelling pro-argument for shale that exists. Big Oil is committing resources to shale in droves. Companies are falling over each other in the attempt to land big "Shale" fish, like Anadarko. And, in so doing have laid out ambitious growth plans for this resource. BP, (BP), ExxonMobil, (XOM), and now Chevron. What are they telling us by voting for shale with their capex dollars?

It's simple really. They are saying that their geophysical teams-which, let's acknowledge are the best in the business, have told them that with scale, they can wring more oil and gas for less money than any other equivalent investment. What scale brings is a low base cost of production, which when combined with the high technology these companies can bring to bear on a project, turns into profits and free cash flow.

Here is what, Michael Wirth the chairman, of what many people regard as the smartest, best run oil operator in the business- Chevron, said regarding this transaction in a recent interview:

"This deal enables us to compete in any oil price environment, produce synergies from the combination of the two companies, and be accretive to earnings in the first year."

A point worth making, and one made by Mr. Wirth, was that it's not only Anadarko's shale acreage drawing their interest, but the global footprint of this company aligning so closely with theirs in deepwater and international. But make no mistake, Anadarko's shale acreage is the linchpin in this deal.

None of the above is really very complex is it?

To summarize this section, in my view as North American shale, and particularly Permian shale, enters its maturity,

• the vast contiguous blocks of acreage,
• with multiple reservoir horizons,
• with the newly built pipeline take-off infrastructure,
• and a nearby domestic processing infrastructure,
• and export infrastructure in place for oil and LNG

it all adds up to a very compelling investment scenario for our production hungry Super Majors, and perhaps foreign companies looking to establish a foothold in this prolific basin.

In my view, Chevron and Anadarko getting together is just round one of the oil asset consolidation wave that will come.

The takeout case for Apache

Apache's, (APA) stock popped nicely on the CVX/APC news, as did many shale players, but fell back a bit as the day wore on. I read nothing into that event.

Alpine High is a massive block of about 300K contiguous acres that has been estimated to contain 3 bn BBOE. As you can see from the slides below, the Alpine High development is skewed to Wet Gas. Wet gas is basically the heavier end of the hydrocarbon molecule with more carbons attached, making them heavier, and tending toward a liquid phase. Dry gas is defined as being 85% methane or better.


One of the things that makes the Permian so prolific is the thickness of hydrocarbon column, up to 6,000'. There are multiple pay horizons, with names like Bone Springs, Wolfcamp, Barnett, and Woodford. Apache has already identified over 5,000 drilling locations across this acreage, with about 75% of them targeting wet gas.
Related: Brent Could Hit $80 This Summer As Hedge Funds Lose Steam

One of the things that's been a drag on Apache's stock was the limited take-off capacity for dry gas. Once Kinder Morgan's, Gulf Coast Express-GCX, line goes into service, later this year, those concerns go away. Apache was one of original subscribers to the GCX, 500 MMCF/D guaranteed take-off.

Cryogenic capacity is the next piece of the puzzle. To turn wet gas into dry gas the heavy ends are first concentrated and removed from the gas stream cryogenically. These units will come on stream this year. The billion or so dollars of capex that's been required to process wet gas has also been a drag on the stock. The market gives you nothing for investing for the future, it's only interested in what's happening now to produce profits.

Section Summary

The goal of this section has been to establish that Apache has built a singular asset in the Permian basin with the capacity to make immediate contributions to cash flow. All aspects of the production cycle appear to be in place.

• Resource development at a high level with costs declining per well and recoveries meeting or exceeding industry standards for wells in this region
• Processing infrastructure in place as capex winds down.
• Take-off agreements in place with third parties for gas delivery to sales markets.

But, Apache is more than just its Permian assets. Not discussed in this article for the sake of brevity are the other assets. We'll bulletize them now for completeness.

• Altus Midstream, Altus Midstream was formed as a JV with Kayne Anderson to service Alpine High's needs. It will be operated as a standalone C-Corp with Apache owning 80%. Trading currently at $5.85/share, it currently boasts a market cap of $1.9 bn.

• Egyptian PSC Apache has operated in Egypt for a number of years, and has recently been awarded new Production Sharing Concessions, PSC's that give it many years of expansion potential.

• North Sea Apache entered the North Sea with the 2012 purchase of ExxonMobil's, Beryl field, and later with the acquisition of BP's Forties Field. In that time it has found significant new amounts of oil. Garten, produced from Beryl Alpha platform has already produced over a million barrels of oil, with additional recoverable reserves of 9-10 mm bbl. Apache has identified two new drilling locations based on the success of Garten.

• Suriname The area on the in-set map outlined in gray with the multiple green dots represents XOMs Stabroeck field development. If you read news related to energy topics, you have to be familiar with Stabroeck. It's the most significant exploration discovery in the western hemisphere in many years. Apache holds a PSC from Suriname for blocks directly adjacent to Stabroeck, and inline with the trend of announced discoveries in that field. Apache drilled a duster in Block 53 back in 2017. Now after examining seismic data for a couple years it's ready to try again in Block 58, later this year. Success could profoundly impact Apache, as XOM has found nearly 4-bn bbl so far in Stabroeck. Apache owns 100% of Block 58.

Suitors for Apache?

Who might be interested? Obviously Shell, which has publically stated as being in the market for a Permian acquisition. Perhaps Occidental Petroleum, (OXY) (which might be a target all by itself)? OXY was in the hunt for Anadarko, and actually outbid CVX on per share basis. There are some who feel there may be another shoe to drop in this matter. Anadarko shareholders have to be rubbing their hands with glee at this prospect, as any new bid would now have to account for the $1 bn breakup fee in the agreement with CVX.

Apache is a prime target to be snapped up a global Super Major, or National Oil company. The game is afoot, thanks to Chevron. All we can do now is wait. Of course, nothing may happen at all in this regard. You never can tell the future with any accuracy.

My view though, we won’t have long to wait!

By David Messler for

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🛢️ Exxon, Chevron Battle it Out in the Permian
« Reply #214 on: April 17, 2019, 08:48:57 AM »

Exxon, Chevron Battle it Out in the Permian
by  Valerie Jones
Rigzone Staff
Friday, March 22, 2019

New analysis by Rystad Energy explores which supermajor has the most potential in the prolific Permian Basin.

On the heels of Chevron Corp. and ExxonMobil Corp. announcing their plans to pump more out of the Permian Basin, energy research firm Rystad Energy is checking to see which company has the most potential there.

The two U.S. shale heavy-hitters both anticipate their Permian production will reach about 1 million barrels of oil per day in the next five years.

But who will fare the best?

Rystad offers five key points:

    Drilling activity: Exxon will have to drill about twice as many new wells as Chevron to reach the production goal. As of 2018, Chevron’s unconventional output in the Permian was 75 percent higher than Exxon’s, so Exxon needs to accelerate drilling activity in order to close the gap and even exceed Chevron’s supply by 2025.
    Rig programs: Currently Chevron doesn’t plan to ramp up drilling in the Permian as it believes the current program is already optimized with respect to well fundamentals and midstream infrastructure. Exxon, however, believes a large scale ramp-up of its Permian drilling campaign is needed to achieve capital efficiency and generate billions of dollars in cash flow from the region by 2023.
    Acreage: Chevron’s legacy land accounts for 1.7 million acres across the Permian Delaware and Permian Midland basins. Exxon currently owns 1.6 million acres in the Permian, including a significant portion attributable to conventional targets in the Central Platform. Chevron has larger upside potential in the Delaware, while Exxon holds more drilling locations in the Midland Basin. Moreover, Chevron’s inventory is expected to deliver an average of five wells per section in Delaware and about six wells per section in Midland, while ExxonMobil will place seven and eight wells per section in each basin, respectively.
    Well economics: Chevron achieves exceptionally low costs for each barrel of oil equivalent (boe) produced in both the Texas and New Mexico parts of the Delaware Basin, standing at below $5 per boe. Exxon’s cost comes out slightly higher at $6.30 per boe, still considerably below the average of between $8 and $9 per boe.
    Scale: In the Delaware Basin, which is less developed than the Midland, Chevron leads in terms of average pad size as of 2018, on Texas and New Mexico sides. Exxon comes immediately after Chevron on the New Mexico side of the state border, with 3.3 wells per pad last year. In the Midland Basin, Chevron clocks in at about four wells per pad, and thus ranks again among the industry leaders.

Rystad Energy’s head of shale research Artem Abramov said Chevron and Exxon will leave all well-established shale producers behind.

“While Chevron is currently leading in terms of well productivity, economics and total Permian output, ExxonMobil is expected to continue to close the gap in the years to come,” he said. “Higher investments coupled with potential well performance improvements are likely to give an edge to ExxonMobil from 2020 to 2030. On the other hand, a larger acreage position with considerable upside potential provides Chevron with an opportunity to continue to grow post 2030.”

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🛢️ U.S. Shale Is Upending Crude Flows In This Oil Frontier
« Reply #215 on: April 18, 2019, 12:49:36 AM »

U.S. Shale Is Upending Crude Flows In This Oil Frontier
By Tsvetana Paraskova - Apr 17, 2019, 4:00 PM CDT

The U.S. shale boom is upending global oil markets as far as crude flows from West Africa to Europe and other parts of the world, and is squeezing in particular Nigeria’s struggling oil industry.

As one of Africa’s top producers, Nigeria is contending with increasingly stiff competition from U.S. light grades on the global market in order to keep its traditional sales destinations.   

Moreover, Nigerian exports to the U.S. have been declining in recent years because the U.S. pumps growing amounts of comparable light crude grades. 

As a result, Nigeria’s crude must compete with U.S. oil—not only in America, but also in Europe and Asia.

Immediate future demand for Nigerian oil is expected to hold up at least for now, as European refiners are buying more light crude to process and export to America as the driving season approaches, and as demand in Southeast Asia—India and Indonesia in particular—supports the prices of the key Nigerian crude grades, says Fotios Katsoulas, Liquid Bulk Principal Analyst, Maritime & Trade, at IHS Markit. 

However, Nigeria faces stiff competition in Europe from U.S. crude, Caspian crude, and North Sea crude, and European refiners are not particularly happy with higher Nigerian crude prices.

Nigeria must also fight for market share in oil-thirsty India, where an Indian state-owned refiner has just signed a first-term contract to purchase American oil.

Despite signs of steady demand for Nigerian oil in the coming months, going forward, Nigeria may have to look for new markets for its oil, according to traders. 
Related: Think Tank: Mexico’s New Refinery Already Doomed

Nigerian exports of crude oil to the U.S. have been on a downward trend for nearly a decade, and the drop became even more pronounced last year when U.S. shale production was beating production records week after week.

This summer, Nigerian oil flows to the United States may find some hope as the market is starting to show some interest in Nigeria’s Bonga grade, and as U.S. drillers cut spending and scale back production, this could also benefit Nigeria’s oil, according to IHS Markit.

“Moreover, the US might experience some further decline in terms of oil well productivity in the Texas’s Permian basin, which could be good news for Nigeria,” IHS Markit’s Katsoulas says.

Nigeria must also compete with U.S. oil for another of its key markets, Europe.

While European refiners could buy more of Nigeria’s light oil ahead of the summer driving season, traders are not happy with the premium of key Nigerian grades to dated Brent, especially when there is cheaper available light oil from the United States, the North Sea, and the Caspian Pipeline Consortium (CPC) crude.

“We have many options that mean Nigerian won’t work for us at these prices,” a trader told Reuters last week, when Nigeria’s key export grades Bonny Light and Qua Iboe were being offered at or above a $2 a barrel premium over dated Brent.
Related: “It’s Stupid”: German Professor Slams Berlin Battery Play

Steady demand for Nigerian crude in Asian countries like India and Indonesia have propped the prices of Bonny Light and Qua Iboe to a near five-year high, according to shipping and trading sources quoted by Reuters.

Nigeria, however, should follow closely how its U.S. competition will play on the Indian market, “as the US have started targeting Indian refiners,” IHS Markit’s Katsoulas notes.

In February this year, Indian Oil finalized a US$1.5-billion term contract to import U.S. crude grades “as a part of its strategy to diversify term crude sources.” This was the first term contract that an Indian public sector undertaking (PSU) in the oil industry had signed to import American crudes.

If the U.S. presses on with more oil sales to the Indian market, Nigeria will have another front on which it must compete with what is now the world’s top oil producer and what was a big buyer of Nigerian crude just a decade ago.

Facing competition in nearly every corner of the oil market, “Sooner or later Nigerian oil is going to need to expand into new markets,” a trading source told Reuters last week.

By Tsvetana Paraskova for


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