E&P Capex And Production Guidance, And Why They Aren't Doing More

[IsailedawayfromFR]

There’s a lot of confusion out there — both in the media and the general public — about how producers in the U.S. oil and gas industry plan their operations for the months ahead and the degree to which they could ratchet up their production to help alleviate the current global supply shortfall and help bring down high prices. It’s not as simple or immediate as some might imagine. There are many reasons why E&Ps are either reluctant or unable to quickly increase their crude oil and natural gas production. Capital budgets are up in 2022 by an average of 23% over 2021. That increase seems substantial, but about two-thirds (15%) results from oilfield service inflation. And there are other headwinds as well. In today’s RBN blog, we drill down into the numbers with a look at producers’ capex and production guidance for 2022, the sharp decline in drilled-but-uncompleted wells, the impact of inflation and other factors that weigh on E&Ps today.

The oil-patch is notorious for its boom-and-bust cycles. For decades, exploration and production (E&P) companies followed an investment strategy that prioritized aggressive growth, including stepping up drilling-and-completion activity when crude oil prices climbed. With oil prices exceeding $100/barrel in 2014, the 43 oil and gas producers we closely monitor invested a whopping $130 billion in drilling and completion to ramp up output. And investors went along for the ride: The S&P E&P index hit a record 12,400 at the midpoint of that year. But the bloom went off the rose when oil prices plunged through the second half of 2014 and most of 2015. Investors left in droves, stock prices cascaded and E&Ps, laden with debt, teetered financially.

When COVID hit in the first few months of 2020, demand destruction of epic proportions caused prices and production to plummet, leaving the oil and gas industry virtually abandoned by investors and the S&P E&P index at 1,200 — only one-tenth its high point six years earlier. On top of that, the industry faced significant risk, not only from the pandemic, but also from the looming potential of an OPEC+ production increase and questions about the long-term prospects for producers as public perception shifted sharply against all things hydrocarbons, institutional investors divested from the sector for ideological reasons, and political opposition became a major hurdle (See Part 1 of this series for more.). To win back performance-minded investors, oil and gas producers instituted a structural strategic policy change, repositioning their equities as yield vehicles rather than growth stocks by drastically slashing capex and prioritizing free cash flow generation to boost shareholder returns.

https://rbnenergy.com/i-cant-go-for-that-no-can-do-part-2-eandp-capex-and-production-guidance-and-why-they-arent-doing-more

Interesting to learn that a lot of the capital increase being spent(over half) is on increased cost of services, not for new activity.  Makes sense with higher crude prices
@Smokin Joe - Were you aware that 20-25% of DUCs are not worth the effort to frac?

[catfish1957]

You and I both understand the information around the nuances arounding looking, finding, and extracting hydrocarbon.

Put this informaton in front of a liberal, and they'll zone out by the second sentence.

[IsailedawayfromFR]

You and I both understand the information around the nuances arounding looking, finding, and extracting hydrocarbon.

Put this informaton in front of a liberal, and they'll zone out by the second sentence.

How true.

Similar to them zoning out when asked the question where the electricity is coming from so they can plug in their EVs.  They know that it comes from a wallplug.

[Smokin Joe]

@Smokin Joe - Were you aware that 20-25% of DUCs are not worth the effort to frac?

@IsailedawayfromFR

That sounds about right, depending on where you are, and in which basin. Even in the Bakken, I have seen wells which simply did not have the reservoir pressures or fluid content to be economical, even though surrounded by wells that IP'd at 1MBOPD or better. (That's 1,000 Barrels of Oil Per Day, not 1 Million, which would be 1 MMBOPD, for those not familiar with industry parlance--if there is a 'e' after that BOPD is stands for "equivalent" and takes into account wellhead gas, Natural Gas, and Natural Gas Liquids ("NGLs"), like propane and butane). With emissions and flaring rules, wellhead gas produced places a limit on the amount of oil that can be produced. In more sane times, that gas would have market value...but wellhead gas has to have:

1: A way to get to a gas plant to be processed into its components, which are a mixture of methane, ethane, propane, Iso- and Normal butane, pentanes, and heavier (longer chain and cyclic) hydrocarbons, and have water vapor and Carbon Dioxide removed, along with other inert gasses should they be present. 

2: A gas plant to actually process the gas into Methane, an other component gasses (NGLs) which are commonly liquefied, except for Methane, and can be transported by truck, rail, or pipeline. The remaining Natural Gas, mostly methane, is commonly shipped by pipeline to either end user distributors or a port to be loaded into tankers for shipment elsewhere.

3: Some way to ship those products, as noted above.

4: Somewhere to ship them to.

Bottlenecks along any part of that chain can cause a problem, especially in view of new regulations being promulgated by the various Federal Agencies involved, which can (and do) create chokepoints in a gathering and distribution system which would otherwise be able to readily adapt to its own needs.

I'd say that percentage of uneconomical DUCs is lower in some basins than others because definite fairways and hot spots are known (and some of the the existing DUCs were drilled there), but other factors come into play besides just the presence of producible hydrocarbons. Some of those wells are just waiting for an ideal price point and forecast that would make fraccing the well worth the investment. The completion alone can cost as much or more as the entire process of acquiring leases, surveying, drilling the well and running a production liner.

While price and production per day are definite drivers, getting the product to market remains a key issue, especially with the current administration's hostility toward pipelines and flaring, the two ways to handle wellhead gas. In excessively gassy reservoirs where the takeaway and processing capacity for wellhead gas is limited, and the lease is being held by production of one or more wells on the pad, it may be advisable to hold off on completing the other wells on the pad in order to wait for depletion of the current producers to open up some takeaway and processing capacity for the additional production to be gained by completing one or more DUCs on the same pad. The economics of drilling the full set of wells on the pad are likely favorable to just drill them all while you have the rig there, but that may not be the case with completing them all at the same time.

The add-on expenses incurred by permitting and other regulatory hoops to emplace production infrastructure can make a marginal well uneconomical (or not worth the capital risk in an uncertain market) and make even an anticipated  relatively decent well a marginal proposition. This is the behind the scenes war the Biden Administration and its Green New Dealers are waging on the industry, one of regulation.  Why dump CAPEX into completions when the future is uncertain, and a change of management at the National Level could reverse the present anti-oil trends, remove some of the regulatory boundaries which have imposed bottlenecks, and restore higher production, which would lower price, making that move a loser, financially?  At this point, the Oil and Gas companies are wise to hold off, bank what they can, drill while the drilling is still relatively cheap, and complete later in a more favorable (and sane) political environment.

High prices are their own cure.

As for the present administration, these people would choke the Golden Goose with red tape, over what has not proven to be the environmental catastrophe they have been bandying about since they stopped hand wringing over the coming Ice Age in the late '70s. IF Sea Level had risen as much as forecast in all the predictions of doom we have had since then, coastal areas would indeed be under water, but instead, the same prophets of doom have been buying up beach front mansions, and the only loss of land is through erosion, mandated by restrictions on stabilizing structures which could prevent that (but that is another story).

[Smokin Joe]

You and I both understand the information around the nuances arounding looking, finding, and extracting hydrocarbon.

Put this informaton in front of a liberal, and they'll zone out by the second sentence.

They go glassy-eyed, then scrinch up their face, and cussing you out...and howl that you don't know what you are talking about...

[IsailedawayfromFR]

@IsailedawayfromFR

That sounds about right, depending on where you are, and in which basin. Even in the Bakken, I have seen wells which simply did not have the reservoir pressures or fluid content to be economical, even though surrounded by wells that IP'd at 1MBOPD or better. (That's 1,000 Barrels of Oil Per Day, not 1 Million, which would be 1 MMBOPD, for those not familiar with industry parlance--if there is a 'e' after that BOPD is stands for "equivalent" and takes into account wellhead gas, Natural Gas, and Natural Gas Liquids ("NGLs"), like propane and butane). With emissions and flaring rules, wellhead gas produced places a limit on the amount of oil that can be produced. In more sane times, that gas would have market value...but wellhead gas has to have:

1: A way to get to a gas plant to be processed into its components, which are a mixture of methane, ethane, propane, Iso- and Normal butane, pentanes, and heavier (longer chain and cyclic) hydrocarbons, and have water vapor and Carbon Dioxide removed, along with other inert gasses should they be present. 

2: A gas plant to actually process the gas into Methane, an other component gasses (NGLs) which are commonly liquefied, except for Methane, and can be transported by truck, rail, or pipeline. The remaining Natural Gas, mostly methane, is commonly shipped by pipeline to either end user distributors or a port to be loaded into tankers for shipment elsewhere.

3: Some way to ship those products, as noted above.

4: Somewhere to ship them to.

Bottlenecks along any part of that chain can cause a problem, especially in view of new regulations being promulgated by the various Federal Agencies involved, which can (and do) create chokepoints in a gathering and distribution system which would otherwise be able to readily adapt to its own needs.

I'd say that percentage of uneconomical DUCs is lower in some basins than others because definite fairways and hot spots are known (and some of the the existing DUCs were drilled there), but other factors come into play besides just the presence of producible hydrocarbons. Some of those wells are just waiting for an ideal price point and forecast that would make fraccing the well worth the investment. The completion alone can cost as much or more as the entire process of acquiring leases, surveying, drilling the well and running a production liner.

While price and production per day are definite drivers, getting the product to market remains a key issue, especially with the current administration's hostility toward pipelines and flaring, the two ways to handle wellhead gas. In excessively gassy reservoirs where the takeaway and processing capacity for wellhead gas is limited, and the lease is being held by production of one or more wells on the pad, it may be advisable to hold off on completing the other wells on the pad in order to wait for depletion of the current producers to open up some takeaway and processing capacity for the additional production to be gained by completing one or more DUCs on the same pad. The economics of drilling the full set of wells on the pad are likely favorable to just drill them all while you have the rig there, but that may not be the case with completing them all at the same time.

The add-on expenses incurred by permitting and other regulatory hoops to emplace production infrastructure can make a marginal well uneconomical (or not worth the capital risk in an uncertain market) and make even an anticipated  relatively decent well a marginal proposition. This is the behind the scenes war the Biden Administration and its Green New Dealers are waging on the industry, one of regulation.  Why dump CAPEX into completions when the future is uncertain, and a change of management at the National Level could reverse the present anti-oil trends, remove some of the regulatory boundaries which have imposed bottlenecks, and restore higher production, which would lower price, making that move a loser, financially?  At this point, the Oil and Gas companies are wise to hold off, bank what they can, drill while the drilling is still relatively cheap, and complete later in a more favorable (and sane) political environment.

High prices are their own cure.

As for the present administration, these people would choke the Golden Goose with red tape, over what has not proven to be the environmental catastrophe they have been bandying about since they stopped hand wringing over the coming Ice Age in the late '70s. IF Sea Level had risen as much as forecast in all the predictions of doom we have had since then, coastal areas would indeed be under water, but instead, the same prophets of doom have been buying up beach front mansions, and the only loss of land is through erosion, mandated by restrictions on stabilizing structures which could prevent that (but that is another story).

I guess I am asking whether, since most premium locations have already been drilled and placed on production, whether it makes sense that 20 to 25% of all future drills will never be fracced as the quality of the formation/pressure/hydrocarbon content proved insufficient to justify completion.

If so, this statistic if integrated properly within a drilling program, greatly increases the overall cost/benefit of the play.

Make sense to you?

[Smokin Joe]

I guess I am asking whether, since most premium locations have already been drilled and placed on production, whether it makes sense that 20 to 25% of all future drills will never be fracced as the quality of the formation/pressure/hydrocarbon content proved insufficient to justify completion.

If so, this statistic if integrated properly within a drilling program, greatly increases the overall cost/benefit of the play.

Make sense to you?

If that is the case, yes. In the Bakken/Three Forks, I think that number would be closer to 1-2%, waiting on higher priced oil and takeaway capacity. If one well on the pad will hold the rest of the lease by production, and use of CAPEX elsewhere will hold even more, the strategy may be to lock in as many lease areas with relatively little completion cost, in order to take advantage of more favorable frac economics. In other basins, that may not be the case.

But let's say 25% are not 'worth fraccing'. If so, then only three of four wells would be economical, and the fourth would be a 'dry hole' economically, which would make the amortized cost of a ten million dollar completed well 11.7  million (approx 50% of the cost of a completed well divided by three for the fourth well) to absorb the expense of the eternal DUC.

[IsailedawayfromFR]

If that is the case, yes. In the Bakken/Three Forks, I think that number would be closer to 1-2%, waiting on higher priced oil and takeaway capacity. If one well on the pad will hold the rest of the lease by production, and use of CAPEX elsewhere will hold even more, the strategy may be to lock in as many lease areas with relatively little completion cost, in order to take advantage of more favorable frac economics. In other basins, that may not be the case.

But let's say 25% are not 'worth fraccing'. If so, then only three of four wells would be economical, and the fourth would be a 'dry hole' economically, which would make the amortized cost of a ten million dollar completed well 11.7  million (approx 50% of the cost of a completed well divided by three for the fourth well) to absorb the expense of the eternal DUC.

Understood.  Guess I am surprised that if industry average is ~25% that the Bakken/3F would be only 1-2%.

The point I make is that some treat the $/boe are for only the wells that produce, but within the portfolio one must include all the DHC as capital as they must be covered by those that make it to frac stage in order to achieve successful economics to continue the program.

[Smokin Joe]

Understood.  Guess I am surprised that if industry average is ~25% that the Bakken/3F would be only 1-2%.

The point I make is that some treat the $/boe are for only the wells that produce, but within the portfolio one must include all the DHC as capital as they must be covered by those that make it to frac stage in order to achieve successful economics to continue the program.

That's one of the reasons the Bakken/Three Forks play has been so good. In the main fairways, which are pretty well understood, wells unworthy of completion are rare. I know of one least that wasn't sufficiently charged to make a good well, something that puzzled us all, because every other well spacing (1280 acres) around it proved to be economically successful. Aside from mechanical problems, well chosen sites yield well.

 That isn't saying there aren't operators who dove in and purchased less successful acreage, but often those operators paid less for leases, and ultimately were either more cautious with drilling, relying as did most early in the play (Elm Coulee Field in Richland County MT was the start) on the revenue from drilled wells to fund their continued drilling.
As many of those early wells, once fracced, produced over 1 MBOD initially, and the drilling, completion, lease fees, etc. were significantly cheaper, those drilling programs grew geometrically during the first few years, then expanded into North Dakota, not as a simple geographic progression, but targeting known areas like the Nesson Anticline and Billings Nose where production had already been established in a few instances in vertical wells.

With that information,and considerable early success, in 2006 the proverbial dam burst and the boom was on.
For the operators who already had significant leases held by production in other zones (Hess, for instance, holding much of the Beaver Lodge Field, Antelope, and others), that worked very well.
Others just coming in were looking at deals for up to $5K/acre lease fees with a 20% royalty, blowing the doors off of the fees and royalties paid previously. Early State auctioned leases in Elm Coulee (MT, 2000-2003) were going for as little as 25 cents an acre, with 12.5% royalties, so the difference was significant, especially as the lease sizes doubled from 640 to 1280 acres and prices for drilling, tubulars, and other services were going up (as they do in any boom).
Aside from a few wells around the fringe, and one I know of where the lateral collapsed due to a frac pumper breakdown, the Elm Coulee wells not only reset the concept of a "good" well (which had been wells with >100 BOPD production in the days of vertical wells), but filled the drilling budgets of those operators who were innovative enough to get results.

Perhaps my perspective is colored by working for an outfit that was very successful in their endeavours, but we had good results almost universally.

Of the 131 Bakken/Three Forks wells I have worked so far, (about half of my career total), only one was a dry hole, and that one was pretty far off the Bakken Fairway. There are others which may have been marginal (I can think of three offhand), but most that I followed did well, producing >1M BOPD, with the best at >3M BOPE.

[IsailedawayfromFR]

That's one of the reasons the Bakken/Three Forks play has been so good. In the main fairways, which are pretty well understood, wells unworthy of completion are rare. I know of one least that wasn't sufficiently charged to make a good well, something that puzzled us all, because every other well spacing (1280 acres) around it proved to be economically successful. Aside from mechanical problems, well chosen sites yield well.

 That isn't saying there aren't operators who dove in and purchased less successful acreage, but often those operators paid less for leases, and ultimately were either more cautious with drilling, relying as did most early in the play (Elm Coulee Field in Richland County MT was the start) on the revenue from drilled wells to fund their continued drilling.
As many of those early wells, once fracced, produced over 1 MBOD initially, and the drilling, completion, lease fees, etc. were significantly cheaper, those drilling programs grew geometrically during the first few years, then expanded into North Dakota, not as a simple geographic progression, but targeting known areas like the Nesson Anticline and Billings Nose where production had already been established in a few instances in vertical wells.

With that information,and considerable early success, in 2006 the proverbial dam burst and the boom was on.
For the operators who already had significant leases held by production in other zones (Hess, for instance, holding much of the Beaver Lodge Field, Antelope, and others), that worked very well.
Others just coming in were looking at deals for up to $5K/acre lease fees with a 20% royalty, blowing the doors off of the fees and royalties paid previously. Early State auctioned leases in Elm Coulee (MT, 2000-2003) were going for as little as 25 cents an acre, with 12.5% royalties, so the difference was significant, especially as the lease sizes doubled from 640 to 1280 acres and prices for drilling, tubulars, and other services were going up (as they do in any boom).
Aside from a few wells around the fringe, and one I know of where the lateral collapsed due to a frac pumper breakdown, the Elm Coulee wells not only reset the concept of a "good" well (which had been wells with >100 BOPD production in the days of vertical wells), but filled the drilling budgets of those operators who were innovative enough to get results.

Perhaps my perspective is colored by working for an outfit that was very successful in their endeavours, but we had good results almost universally.

Of the 131 Bakken/Three Forks wells I have worked so far, (about half of my career total), only one was a dry hole, and that one was pretty far off the Bakken Fairway. There are others which may have been marginal (I can think of three offhand), but most that I followed did well, producing >1M BOPD, with the best at >3M BOPE.

You may recall that during my working days last decade that I consider the Bakken the purest unconventional system in the USA and maybe the planet that is unlike any others I have seen.  It is one reason Crude will become more scarce in decades to come.  Most "unconventionals" do not have such widespread conformance or frac ability as the Bakken and are essentially more of redrilling fields with horizontal wells multistage fracced rather than true unconventional plays.

[Smokin Joe]

You may recall that during my working days last decade that I consider the Bakken the purest unconventional system in the USA and maybe the planet that is unlike any others I have seen.  It is one reason Crude will become more scarce in decades to come.  Most "unconventionals" do not have such widespread conformance or frac ability as the Bakken and are essentially more of redrilling fields with horizontal wells multistage fracced rather than true unconventional plays.

Interestingly enough, while running Mass Spec on well gases from a Wolfcamp well in west Texas, we identified several reservoir boundaries in the lateral. I do not think those formations are as layer cake as people seem to assume, and I know for a fact that few carbonates (even in the Williston Basin outside the middle Bakken and Three Forks) are, either. Horizontal drilling in discontinuous reservoirs will enable production of reserves otherwise missed on larger leases (and even smaller ones, as demonstrated in early short laterals done from former producing wells in the Mission Canyon near Tioga, ND).
What the Bakken has going for it is that the formation only exists in the subsurface, pinching out as the Basin shallows, so the system was sealed. Depositional environments are pretty consistent throughout the respective members over a large area. The Three Forks has multiple benches (4, to be precise), but the vast majority of production only comes from the upper two, with exceptional wells in the hot spots having some success in the third bench. The fourth bench is mostly arid environment oxidized (red bed) lithologies that seldom have hydrocarbon shows. But below all that, there are nine other formations known to have oil (though not unconventional) and two noted for gas.
I foresee the lack of knowledge about those formations, shows in them, and their characteristics as more of an impediment to future production than just running out of unconventional reservoirs. i have only been on five wells in 20 years that were vertical wells (all others had some directional component in them), and of those five, none were in the Williston Basin. I would think other basins suffer from the same problem, and improvements in drilling technology will make those reservoirs harder to spot, not easier.

Not limited to just one basin, I know of an area in yet another state with great potential, which (like the Bakken generally was) is dogmatically considered to not be producible. I haven't followed up to see if anyone has attempted it. While drilling laterals there might prove challenging, I would love to see it tried. Hydrocrbon shows were noted throughout that area, even though it is not as extensive as the Bakken/Three Forks, but the lithology is consistent, as are shows of hydrocarbons in that formation in the area, and it has potential to be something worthwhile.