With public and private upstream operators looking at alt funding to continue growth of operations, private equity-backed companies are also taking alternative approaches to their business.
After the downturn of 2016, private equity jumped into the oil patch to the tune of more than $100 billion and counting. Some of the most active quarters over the past few years have seen more than $20 billion deployed. Arbitrage was seen between the low prices of upstream assets that companies were unloading versus their inherent value; investing the time and money was a no-brainer for most funds.
The problem that private equity has always had: exit strategy. If timed correctly, they will jump into the market at, or near, a low to provide liquidity to the market and then jump back out as public companies have the capability to acquire. This was prevalent over the past few years as we saw upstream transactions reach more than 300 deals in 2018 alone, representing more than $80 billion. However, we live in a cyclical market, and if not timed correctly, private equity can be caught holding the bag.
Figure 1: Private equity raises through Q3. Enverus Capitalize.
As capital has dried up for public E&Ps due to hedge funds and investors demanding a return to profitability and banks shunning risk inherent to the sector, private equity has had a harder time cashing out. This is both due to a scale and liquidity issue. Consolidations for many larger E&Ps require what is known as “moving the needle.” This is a scale few companies reach (generally $1 billion and greater) as a standalone portfolio company.
On the other side, small and mid-cap operators don’t have the balance sheets to acquire due to the multiples being demanded for private equity to satisfy investors. Private equity is also less likely to take a stock transaction, which is easier for small- and mid-cap companies, as it is hard to show value to their investors if they become tied up in a public market with flighty retail investors.
The risk is more inherent on companies that received funding more than four years ago, as the typical fund has an initial life span of five years, with an extension of up to an additional five if investors so choose.
As the end life of a fund becomes clearer, the investment committee is less likely to allow capital to be deployed for fear of not getting a significant return prior to redemption notices. Now, some funds can roll forward and many have investors OK with an extension of the fund life. However, the writing is on the wall right now that many of these companies will not have an exit anytime soon, begging the question, “How does private equity exit?”
The short answer is they don’t. Instead, they flip the script.
Instead of buy-and-flip, they become operators themselves. The return to this strategy goes back to the days of DrillCos and joint ventures, where investors’ returns were more based on cash flow of exploiting the asset and tax deductions from drilling and completion expenses, rather than a quick flip. It is a different type of risk than buy-and-flip but is a time-proven model for good cash on cash returns.
Figure 2: Count of private equity-backed companies by basin. Enverus PE Database.
Figure 3: Total committed private equity capital by basin. Enverus PE Database.
The negative of this buy-and-operate model is that you need less portfolio companies within the fund to exploit assets under management. More private equity sponsors are starting to consolidate their portfolio companies to lower overhead expenses, but also to grow the asset base and drilling program potential for what will become their hold strategy.
By consolidating the portfolio companies, private equity sponsors are also making the assets more attractive to larger buyers that can still float bonds or equity to acquire assets. Consolidation is not limited to within the fund that the portfolio company is in. Cross-fund and cross-sponsor consolidation is also occurring to maximize the value of the assets these various sponsors hold.
Like many industries, buyout private equity has a large amount of dry powder to deploy, and with the recent shutting of capital markets to public companies, a new life has been given to private equity. Unlike a public operator, private equity can shift strategies to maximize returns based on what the prevailing market needs.
Capital deployment for upstream has started to shift focus to minerals and alternative lending strategies. By providing the liquidity the market needs to make deals happen and to allow operators without the capital availability to grow, private equity is more important than ever.
DrillCos are fundamental in allowing operators to prove up or grow an asset that is non-core compared to selling in a buyer’s market. Mineral acquisitions tied with upstream private equity-backed companies give additional value to acquisitions by providing higher net royalty interests and an alternative cash flow. These consolidated assets of minerals and producing properties are more attractive due to their long-term value in stacked plays. If an operator buys a private equity-backed company that owns the majority of minerals under its producing assets, you answer only to yourself where pooling laws exist and more revenue is retained, raising both net present value and internal rate of return.
We have seen less companies being funded in this transition to buy-and-hold as well as a rise in alternative funding. What is yet to be seen are the long-term implications on basins and offset markets, such as oilfield services, as we have more private operators developing assets.
Private equity tends to be more forward thinking, pushing the boundaries of basins, plays, and economics. They have spurred the growth and interest in basins such as the Permian, Powder River, DJ (Wyoming), Uinta, and Haynesville. Will the shift affect our growth as an industry and the movement to new undeveloped plays? Will we begin to see less exploration and exploitation onshore? Only time will tell how the public markets shunning of providing capital will affect the growth of our industry.
Figure 4: Rig market share, public vs. private. Enverus Rig Analytics.
Figure 5: Completion market share, public vs. private. Enverus Engineering.
As we look to the future of liquidity and capitalization within our industry, we must focus on both public and private markets. Private equity, like hedge funds, provide liquidity to markets when conventional avenues are closed. They are the innovation drivers for expanding plays and improving efficiencies like venture capital is to technology companies.
While public markets are going through a fundamental change in our ever-cyclical market, private equity will fill the gap to ensure that we as an industry move forward. For public companies that are facing financial headwinds, private equity will be the one coming to their aid. It might not be this quarter or next, but as companies start to feel the pressure, or face selling an asset at a lower than needed multiple, private equity will be there.
Public companies come and go, PE will always be around. If you don’t believe it, look at how much money the largest funds have raised over the past year in anticipation of future exploits, more than $100 billion in 2019 alone that will be deployed over the next five years.
Following the money isn’t the easiest. Enverus has tracked more than 6,000 private equity events over the years to keep an eye on these trends, more than 600 of which are shown in Figure 6 depicting the fund raise and closure over the past few years.
Figure 6: Closed and announced raise of private equity funding by quarter. Enverus PE Database.
According to a recent study by The Economist, more than 44% of home mortgages in 2018 originated from non-bank lenders, compared to just 9% in 2009. It seems everywhere you look alt lenders will loan money at lower interest rates and in quicker time than a traditional bank. While banks have layers of bureaucracy to go through, and for good reason, alt lenders only have their financial backers to answer to.
Some alt lenders crowdsource their funding so all risk is on the individual, much like an investment vehicle. In reality, consumer alt lending is new to the market, but business alt lending is not. Oil & gas companies have always had creative, and sometimes confusing, alt lending structures such as DrillCos, overriding royalty interest (ORRI), and asset-backed securitization (ABS). Let’s take a look at these three structures to better understand where the market is heading in terms of alt lending for oil & gas.
Figure 1: Study on alt lending rise within the mortgage industry.
Figure 2: Alt lender PayPal growth of consumer loans.
DrillCos are the oldest alt lending products for oil & gas. With the enormous amount of “dry powder” private equity (PE) has, and poor alternatives operators have to fund drilling, these have seen a resurgence recently.
Even larger independents use this structure on non-core assets that they don’t want to deploy capital or time to. It allows them to maintain ownership of the asset while lowering costs by turning the acreage to held by production (HBP) status. A DrillCo is where a financier will pay up to 100% of the costs to drill and complete a well for a certain percentage of the working interest that is reduced as hurdles are met. They will maintain a minority ownership stake in perpetuity, or it will convert to an override after hurdles are met. This allows them to receive the tax advantage of drilling a well with a long tail payout. A simple example is a financier providing 100% of the capital to drill and complete a set of wells for 75% working interest. This would mean the operator has a carried interest of 25% until hurdles are met. Once the hurdles are met, the financier’s interest is reduced until it is a minority interest, or it can convert to an override.
EOG employed this strategy in their Ellis, Oklahoma, acreage which allowed them to prove up the asset without deploying much of their own capital. If the DrillCo is structured correctly, there is a lot of upside left for the operator after the initial wells are drilled, holding acreage and lowering unit costs as infrastructure and locations are already proven. Other DrillCos announced include CRC Resources, EP Energy, Eclipse Resources (now Montage), and Ascent Resources. Some PE firms have raised exclusive funds for the deployment within DrillCos; GSO Capital Partners used $500 million in funding for Sequel Energy II which focuses on DrillCos.
For PE firms, a DrillCo allows them to put capital to work without the overhead management of internal teams. Their capital isn’t going toward grassroots leasing or the crowded world of bidding on an asset; instead it is being directly deployed into an asset and well. This creates instant value for investors and allows them to use tax advantages in regards to drilling expenses to further bolster returns.
Figure 3: Dry powder (committed) among all private equity companies.
Overriding Royalty Interest
Canadian E&Ps have used overriding royalty interest (ORRI) as a form of alt lending for decades, while this is just starting to take hold for public E&Ps in the U.S. Compared to a loan, an ORRI allows for the operator to shift some risk to the override buyer. With a loan, operators pay a fixed rate regardless of overarching commodity prices.
More operators are floating longer-term bonds to try and reduce near-term commodity and interest rate changes. An override for cash today, eliminates the commodity and changing interest rate environments as you pay a fixed amount of cashflow. This places more risk on the owner of the override and allows companies to remain flexible and not have to take on additional debt. Now, over time the override can be more expensive than a traditional bond or equity issuance, but since that market has been stagnant, operators must find other ways.
The prime example of an operator using an override to reduce debt is Range Resources. They have issued 3.5% ORRI, in total, for more than $1.15 dollars. In the near term, this will not affect much of their cashflow as the override is on 350,000 acres, which is not fully developed. In total, the cost net to them in year one will be approximately $85 million, but will allow them to reduce debt by $1 billion. The two buyers of the ORRI will continue to see their cashflow increase, or at the very least maintain, as Range continues to drill on the property and pricing recovers long term.
||Cashflow to Buyer, Year 1
There is also opportunity for public mineral companies to participate in these ORRI financings. By partnering with a company in a basin, public mineral companies can secure long-term revenue without changing their business model. Operators in turn would receive the funding they need to reduce debt or increase drilling activity and the relationship becomes mutually beneficial. As more mineral companies become public, there will be a crunch in the market for deal flow to maintain growth and revenues; companies will have to come up with interesting ways to grow their business. Why not partner with an operator and own the drilling schedule?
Figure 5: Debt issuance in 2019 using Enverus Capitalize shows an all-time low until Q3 (Oxy and Exxon accounted for more than 50% of total issuance in Q3).
Figure 6: Equity issuance in 2019 from Enverus Capitalize report.
The newest form of alt lending we think might get some traction are asset-backed securities (ABS). By securitizing an asset, it opens it up to more investors looking for yield from a financial product that has an investment grade. Asset-backed securities also differ from other financial products as they are a financial product backed by a hard asset, such as royalty streams.
The benefit of an ABS is that risk is lowered as you pool together various streams of revenue that otherwise could not be sold on their own, for instance, hundreds of small royalty payments. The problem that will always exist for oil & gas is determining the value of the assets we own. Real estate is more straightforward, payments stay the same and delinquency rates are low for certain tranches while the underlying asset appreciates in value. Oil & gas assets decline over time unless new drilling takes place, but at the end of the day almost all assets go to zero.
Raisa was able to securitize non-op interests across 700 wells, which reduces risk of non-payment. It is much harder to show up at a well site and take ownership of your percent, however, than foreclose on a property. The ABS sold by Raisa has been compared to aircraft and railway issuances except, that those industries yield closer to 4.5% compared to Raisa’s ABS, which is 6% or more—meaning buyers are still unsure of the underlying risk of oil & gas assets.
There have been questions on how PE will exit their investments if the market is not willing to accept the multiples they request. One thought was that larger funds could create a separate debt fund to pay out investors. The problem is that this saddles PE-backed operators with a debt-loaded asset that reduces their ability to scale and grow. Many of these companies can get ratings on their debt, but it is still close to or at junk status. The ABS provides another avenue that would be open to additional investors on the street.
For mineral companies, both public and private, this might be one of the better routes to take if public investors won’t allow for additional debt or equity issuances. Since Raisa is the first one to complete one of these security issuances, it will be interesting to see if additional requests are made. If there is one thing the street likes, it’s new forms of investments to sell.
Will we see insurance products pop up if ABSs take off? Will there be other products similar to credit-default-swaps, as we see in the mortgage industry? Reinsurance? If (and it’s a big if) this takes off it will raise the question of to what limit will be placed on derivate products that are created, and that could create a house of cards.
With politics starting to heat up for primaries as we head into the end of year, fracking has taken a front seat in a bad way. Every Democratic front-runner has stated a ban or limitation to fracking in the U.S.
While few believe they could pass a total ban on fracking, it is not out of this world to think they could put a short-term ban or moratorium on fracking within federal acreage. This would create a perfect storm for some basins that are comprised mostly of federal acreage such as the Powder River and parts of New Mexico.
Over the years, the industry has seen short-term federal bans for lizards and birds that have lasted months to years and have added thousands of costs per well. A new ban could be hidden as another review of policy if opposition seems high.
Figure 1: Democratic presidential candidates and fracking stance.
Federal leases have been seen in an increasingly positive light lately due to their low royalty rates and long lease terms. These benefits far outweigh the additional paperwork and cost of operating on a federal lease.
In Wyoming, we have seen the review and passing of large-scale projects that will bring thousands of jobs and hundreds of millions in revenue for both state and federal governments. These projects will be in limbo if a new ban is enacted; hurting both local and state economies.
Our industry is one that does not forget deceit; a short-sighted ban or limitation of federal property would create a long-lasting black eye for federal leases. This could lead to higher unemployment for not only our industry, but the states that have seen this increase in activity. It would create bust towns that are not due to macroeconomics such as oil price, but politics.
Figure 2: Large-scale project in Powder that comprises 1.5mm acres of land and five operators.
As we go through this next year, we will have to start looking at the risk operators have based on their Bureau of Land Management (BLM) acreage holdings. We will start to see some companies hedge their risk by buying acreage or companies with lower risk fee acreage. However, this will take either investors willing to allow a company to take additional debt, or willing to issue equity to finance. Are investors willing to allow a company to spend the money needed to make this hedge? Are there enough deals out there to be had for companies that will fall into this risky category?
While this will not inherently impact current operations by operators, it will affect future production from basins that are just starting to hit their stride. Since most shale wells decline more than 50%–70% in the first year of production, a ban of any significant time would create a decline of overall production.
Since the basins most affected by federal leases are Gulf of Mexico (GOM), Powder River, New Mexico, and Northern DJ (Wyoming), oil production decline from these basins would need to be offset by increased production from other basins.
This would create an arbitrage opportunity for companies in oil-weighted basins such as the Eagle Ford and Midland Basin. Their proximity to both refineries, new pipelines coming online, and similar API weight to these federal positions would be optimal. For operators in these basins, we could see an increase in valuation of assets compared to their federal counterparts.
Figure 3: Wyoming oil production based on first production date.
Inherently this could also create a short-term squeeze on financials for companies that are single-basin operators. Many of these basins are held heavily by private equity-backed companies that would luckily not send shockwaves through our industry’s public sector. There are several household names however that have significant positions and growth based in these basins.
Oilfield service companies, in anticipation, will start to move equipment and contracts to basins with less political risk putting pressure on service prices. If pressure continues to build, midstream companies and transporters will also start to look to hedge volumes on pipelines to ensure they can meet the demand of refiners.
A spiraling effect always takes place in vertically based industries; something a new administration should consider. While we have complete faith in our industry to shift dollars and production to lower risk regions, the long-term effects on these basins will be felt.
To get a sense of the size of federal land holdings and areas of responsibility, look at the map below.
The question for our industry, investors, the general public, and especially politicians is, “Have you thought of the implications of banning the so-called ‘dirty frackers?’”
Talking with multiple oil field service companies over the past few quarters, the discussion around costs is weighing heavily on many minds. As oil prices have risen over 50% from lows in 2016 (Figure 1) service costs have stayed flat to declining; many oil field service companies are losing money on every transaction. In a report on FuelFix there were over 108 oilfield service bankruptcies from 2014-2016, some as large as one billion dollars. Some might argue that OFS companies took the brunt of the downturn losses in terms of people, work, and money as E&P companies forced costs to unsustainable levels to meet their obligations.
Figure 1: WTI Spot Price Q4 2013 to current (Source: Fuelfix)
The issue ahead can be boiled down to market share vs profitability – keep prices low to gain market share or raise costs and begin to generate returns. Depending on whether a company is public or private, has notes coming due, etc. can drive this discussion in multiple ways. Using engineering data from Drillinginfo we can see that production from wells over time has increased per 1,000’ of perforated lateral and overall (Figure 2). The reason we look at production in a normalized fashion is to see if we are incrementally increasing efficiency in production— meaning we are getting higher returns per normalized foot. In some instances we will see that production is increasing un-normalized but decreasing when we normalize. This leads to the question of whether we are drilling longer laterals which is increasing overall production but producing less efficiently per normalized foot. This is sometimes inevitable when down-spacing occurs in development plans but can also mean that the cost to drill a longer lateral is less than the overall incremental return in production even though we could be producing more from a shorter lateral per normalized foot.
Figure 2: Proppant Volume over time per 1,000 ft of perforated interval
Figure 2.1: 12 Month Cum Production Per 1,000 ft of perforated interval
Proppant volumes have also increased across all basins but the costs associated with increased proppant volumes and various other chemicals used in completions are vastly outweighed by the increased production. In basins such as the Midland and Delaware we are seeing an increase in over 30% YOY (year-on-year) production growth when looking at vintage type curves. Even though this increase might not continue as we move into downspacing sections, the increase in production and subsequent EURs will yield higher returns than older wells using lower proppant volumes.
Figure 3: Delaware Basin Vintage Decline Curve
Figure 4: Midland Basin Vintage Type Curve
Figure 5 (partial data for 2/2017) shows what the rig count is telling us—that most basins are seeing either stable or increased activity as prices begin to stabilize or slightly increase.
Figure 6 shows the incremental change of DUCs from that drilling activity over the last year; we have decreased the overall amount of DUCs but by very little. During October and November of 2016 we can see we increased the number of total DUCs before completing a large quantity in December. As more wells have been drilled in the past couple months the overall DUC count is staying flat meaning we are completing almost as many wells as we are drilling. Again, these returns are being realized by E&Ps but have not translated to service companies. With more rigs coming online, an increase in the DUC count can occur when there are not enough completion services to go around.
Figure 5: Wells drilled over past two years by basin
Figure 6: DUC count over time across the US
Job cuts in excess of $500k over the years have led to a downturn in qualified personnel, not including the equipment that has been sitting idle.Cannibalizing equipment to keep other equipment running, foregoing services on equipment to keep cash flow positive impedes the ability of the industry OFS to bring on new crews. Currently companies are waiting 3 months for a new fleet to be built; how will this change if demand for new fleets ramps up 50%? Efficiencies in completions can only go so far as the time it takes to complete a well; lean six sigma practices can be used for supply chain management but doesn’t help a lot if the supply chain is empty.
Another discussion concerns sand and various chemical costs. Currently we have not seen much of an increase in costs of proppant but there have been discussions of costs rising 10% or more on certain types of proppant. This is due to multiple factors—increased activity, longer laterals, and increased proppant volume per ft are raising the volume of sand needed per job. Compared to 2014 (graphic on sand per 1000 ft over time) we have seen an increase of 100% in the Delaware in terms of sand volumes and 38% in the Midland. The average horizontal well in the US is using 9.2 million lbs of proppant per well with some testing upwards of 30 million lbs. Begin to multiply those figures by the average number of wells being completed per year and compare it to the output of sand mines across the US. Compare it to the associated costs to transport that sand by rail and truck to location and then contemplate continuing to increase the average total volume per well as we have in the past couple years.
Figure 7: Proppant volumes horizontal wells completed onshore US
Figure 7.1: Proppant Over Time Delaware Basin
Figure 7.2: Proppant Over Time Midland Basin
The demand this has on mines is incredible. With operators moving to finer meshes and mixes, it only makes sense for proppant suppliers to raise prices to counter the rising demand. These costs will be directly passed on to the E&Ps who will have to deal with the rising costs of in-demand services. The clash between these two parts of industry could be economically compelling since publicly traded E&Ps have issued guidance on returns based on specific costs which will be inaccurate if service costs rise. The question is, how many companies will push back? Figure 8 looks at the breakevens of Operators in the Permian with 20% returns at $50 WTI and $3HH with flat service costs on the left and 20% increase in service costs on the right. One can see the number of Operators and regions that become out of the money just in the Permian; this will affect other regions that have higher service costs due to location, etc. in a negative way.
Figure 8: In the money operators with $50 WTI, $3 HH, and flat service costs and 20% increase
Currently, service companies have the upper hand. Many are fully contracted out for services. Companies late to the game will have to pay to build fleets or wait in line, adding additional costs to completion schedules that will have to be met. If pricing goes back down, these operators will be on the hook for the fleets they helped build which would lead to the same issue we saw during the downturn with rig contracts; E&Ps paying to break the contract. On the other hand if pricing is sustained this could give them a leg up with a fleet built for their wells. Service companies are starting to work for who they want, not for who will pay, leading to a scrutinizing of companies that are late on payments, poor partners, etc. Holding the line for E&Ps might not be possible. Rising service costs and subsequent downward pressure on returns will hopefully not start another vicious cycle between the two sectors.
Coming on the heels of the last few articles about DUCs (drilled uncompleted wells) another discussion that is beginning to occur between analysts and companies is the shortage of equipment and manpower. Since pricing began to slide in 2014 over 350,000 people have lost their jobs across the United States and around the world from service companies, E&P’s, etc. While these cuts were necessary due to the cuts in CAPEX and D&C budgets. The question is what occurs if pricing and liquidity in the commodities market opens up allowing for E&P’s to begin drilling and completing wells again? According to the IEA’s outlook oil market is set to balance in second half of 2016 begging the question of whether this shortage will occur sooner rather than later.
By using DrillingInfo’s rig analytics and DUC monitor we overlayed strip pricing by month to see how the number of DUC’s compares to that of pricing. The question that remains is what pricing will it take to begin completing these DUCs; strip or hedged?
Through price swings up and down the general trend is that as things pick up more field workers are hired and crews get back to work. There is some lag time as equipment needs to be fixed and prepared to get back to work and workers need to be retrained on equipment. This shortage creates a small price pop due to increased demand of services and a shortage of equipment and people that generally fixes itself over a relatively short time frame. A price rebound today might be different than those of past; the main reason DUCs. The number of DUCs around the country is topping 3,304 (as of 6/12/2016; taking into account a 6 month time lag in accurate reporting) across multiple basins and hundreds of operators as seen in the figure below. While there is enough HP in the market currently to serve the wells that are being completed what will occur when operators begin completing DUCs and drilling at the same time? The lag that was limited to new drills and limited DUCs that were mostly conventional wells will now be under strain as these DUCs are first on the block to be completed followed by new drills. This will create an artificial lift in pricing not based on hydrocarbon volume but equipment shortage. Equipment and personnel will not be able to safely spin up as quickly as needed which will create an additional backlog of wells needing to be completed. This circular issue can create an extended period of time where pricing will be based off of shortage of equipment to get hydrocarbons to market compared to the world commodity market itself. This could create an incredible arbitrage for those trading commodities and those producing them as well as service company costs not seen since oil last topped $100/bbl.
Figure 2: DUC Counter DrillingInfo Rig Analytic looking at wells spudded through November 2015
The ease at which new rigs can enter the market is dependent on the drilling companies that have stacked rigs, their locations, and if they have been stripped of parts to save money. An overview of stacked rigs vs active and marketed can be seen in the graphic and table below; which was pulled from DrillingInfo’s Rig Analytic.
Table 1: Stacked Rigs DrillingInfo Rig Analytic
One can assume that the companies with the highest active rigs also have the highest stacked rigs as they as the largest drillers in the lower 48. If those top operators are stripping parts from their stacked rigs it should be fairly unoticable in terms of the total HP they have ready to deploy. The struggle for those companies will be maintaining their large fleet and active rigs; they will only have a certain amount ready to deploy at one time allowing others to fall into categories of needing repair. The smaller drilling companies will struggle more as stripping parts from their small pool of stacked rigs will not allow them to deploy extra rigs in a timely fashion. If they have good cash flow they should be able to maintain a certain amount of their fleet but will still be at a disadvantage to large drilling companies which have more capital and yard locations to move equipment around at cheaper costs.
Table 2: Stacked Rigs Location by Basin DrillingInfo Rig Analytic
Continuing on looking at lower 48 stacked rights, the locations where these stacked rigs were last located before moving to their resting places can give an idea of where they might be located. Even Though certain basins like the Appalachian basin have been hit hard by pricing and decreasing rigs, the percent of active rigs to those stacked in their respective regions are less than that of Texas. This can be skewed some as Texas is a large state with multiple plays that have been hit hard by the downturn but is an interesting view nonetheless. States with the highest stacked rigs for the lower 48 can be seen in the table below.
Table 3: Stacked rigs last known state DrillingInfo Rig Analytic
Looking at the HP of the rigs stacked we can get a general idea of the percent of horsepower stacked versus active in the country for the lower 48. Using DrillingInfo’s analytics platform we can do this by basin, state, drilling company, etc. to get an idea of how different regions compare to one another.
Table 4: Low with stacked rigs horsepower DrillingInfo Rig Analytic
While we cannot forecast how things will look in a year from now, recently we have seen pricing in both the futures and daily markets increasing. The additional help of LNG exports and new pipeline capacity being added to the north east should help some as well. If we as an industry do not look at what it will take to increase production and efficiency we will be fighting an uphill battle. This might not be all bad as a continuous increase in pricing will benefit the industry but this will be a new frontier for all, as shortages will take place on multiple fronts. Not having enough rigs and completion crews is one battle, not being able to complete wells that have been waiting 12+ months, along with crew shortages and new wells being simultaneously drilled will be an interesting situation. I for one am ready to go through this new frontier and hope we have learned mistakes of past.
What do you think? Leave a comment below.