Much open discussion through the press has been given to the ‘break even price’ as it relates to the ability of producers to economically develop shale oil resources in a low-price environment. The range of prices has been stated by many parties ranging from as low as $20 per barrel to more reasonable projections of between $50 and $60 per barrel in the next 6 to 12 months. The break-even price estimates are the basis of increased activity as reflected by the surge of active rigs since the fourth quarter of 2016.
Conventional wisdom includes three elements in the determination of an oil play’s economics: well productivity and ultimate recovery; capital cost; and operating costs. A fourth and often ignored element, is the cost of capital and land acquisition.
First let’s look productivity and ultimate recovery. In a two-section scenario (10,000-foot laterals); if a producer ‘exploits’ a 200 foot pay interval, the ‘fluid’ in place (in a wet gas region) is about 79.3 million barrels of fluid. Assuming 6 wells, 10,000 feet in length with a 40-stage completion, each producing 1,000,000 BOE equivalent, the wells recover about 8% of the resource in-place. However, if the well has an ultimate oil recovery 600,000 barrels, the other 400,000 BOE equivalent is represented by 2.4 Bcfd of wet gas. The relatively low light oil and condensate production is due to the shrinkage of the oil and condensate due to the liberation of gas as the reservoir is drawn down (as I will explain below).
Phase behavior – a function of molar composition, temperature, and pressure – and permeability determine the rate and composition of the fluid produced and rate at which it is produced. Setting aside permeability which we will assume is constant (see below) phase behavior essentially determines composition of produced fluid. The key factor is the ‘bubble point’ which is defined as the pressure and temperature at which a liquid begins to break into a liquid and gaseous phase. The lower the pressure and temperature (near wellbore cooling exacerbates this), the more gas is produced – the gas/oil ratio (GOR) increases. For example, wet gas at 10,000 feet with a reservoir pressure of 5,300 psi (1.2 times over-pressured) has a bubble point of 2,600 psi. In theory this means that liquid will drop out as the reservoir pressure drops roughly by half.
In practice, this does not occur. Two factors are at play. The first is that to produce at economic (or in some cases foolishly buy pulling too hard) rates, the near wellbore pressure is usually well below the bubble point, and cooling by the Joule Tomson effect also cools the well. The region of lower pressure moves away from the frack face as the well is produced. With high intensity fracking, this explains initial high rates, with high declines and increasing GOR. The prudent way to manage productivity and ultimate recovery is to closely manage pressure by a process called ‘slow back.’ Slow back simply means producing wells at lower initial rates for a longer period. Slow back can improve recoveries by as much as 20%. It is safe to say that as a general rule when it comes to productivity and recovery, roughly two thirds of production is seen in the first two years with the remainder over fifteen or twenty years.
Capital expenditures are perhaps the easiest factor to calculate, right? It is simply the cost of drilling and completions. But what are often forgotten are facilities costs which include wellhead separation, compression, artificial lift (pump jacks do not work well in high GOR situations) requiring expensive gas lift facilities, pipelines, water handling infrastructure and gas plants (if no third-party facilities are available). Facilities can add up to as much as $2 million per well.
Capital efficiencies recently seen on the drilling side are primarily the result of better drill bits and mud in the vertical section (only one vertical section is required in 10,000-foot lateral versus two 5,000 laterals), and the advent of rotary steering. Rotary steering simply means that the well can be steered while rotating, eliminating the need to make trips to guide mud motors. This innovation has cut days off the time to drill lateral sections. Drilling longer laterals means that on a per foot of lateral basis, costs have come down (which sounds pretty good). But as in any ‘sport,’ less rigs deployed has meant that key personnel have been kept, often having drillers and tool pushes ‘demoted’ to floor hands. Another means to keep the best hands has been to reduce shifts from three weeks on and one off to two and two, respectively. Up to a point, drilling efficiency results from the employment of major league all-star drillers. These guys can and do rock. However, once activity picks up, increasingly green hands will be needed and time will be needed to meld each crew. Unfortunately, Some may never gel.
Finally, at some point, drilling companies will need to raise day rates to make money to train less efficient crews and to modernize their fleets (all producers now require walking rigs with Star Wars controls). Clearly, the largest producers who have kept up some level of activity will retain the best crews and will be able to negotiate the best rates (yes there is loyalty in the patch for having been kept working through the bad times). Producers who are small or late entrants will not have the same drilling capital advantages as the players in it for the long haul.
Completions have also seen great advantages with higher pressure rated equipment (to over come pressure drop over long laterals) and more sophisticated down hole tools allowing up to 60 stages per lateral. This technology is referred to as the ‘ball drop system.’ In the ball drop system, the ports are set in the production string at pre-determined intervals. The ports are closed until the right sized ball opens the right ports from the end of the well to the lateral kick off point. The balls range in size from 3.75 inches to 1.5 inches. Immediately after the price collapse, pumping and sand suppliers cut costs to the bare minimum. As activity has picked up, both pumping and sand costs have risen by as much as 30%. Increased frack stages have bumped up the total completion cost, but this is offset by more productive wells in conjunction with longer laterals.
I’ve learned to say never is a long time. As I discussed above, great technological advances have been made, but to me, the pace of advancement will likely slow. As prices rise, supply and demand teaches us that costs go up as does demand. As I recently read, in times of a slowdown, producers want cheap, but in good times, yesterday is too late. In the latter case, cost and train wrecks tend to be forgotten.
Operating costs are the most boring aspect of oil and gas production. They are however, one of the most important economic indicators. After all, a one-dollar per barrel saving is a one-dollar price increase. Basic lease operating costs include those costs incurred to lift, compress, and separate gas, oil, and water. This generally includes company and contract labour, chemicals, and equipment maintenance. Individual well operating costs tend to go up over time as more compression and artificial lift is required and production decreases.
In addition to lease costs, other cash costs are incurred including payment of freehold royalties, ad valerom taxes, surface lease rentals, transportation and third-party processing.
As I mentioned above, capital, and operating expenses are the usual yard sticks for determining rates of return and break-even economics. However, the cost of acquiring land and the cost of capital must be included to determine if the individual producer is making a decent rate of return and truly adding value. Land costs in the Permian have ranged recently from $15,000 per acre (purchase of 75,000 acres by Exxon for $6.6 Billion in February 2017) to as high as $50,000 per acre. The lower value totals $19.2 million for two sections or $3.2 million for each of the 6 wells needed to exploit this land parcel. In the higher instance, the total land cost is $64 Million or $10.7 million per well. Clearly these wells will never by economic unless prices rise above $80 dollars per barrel. Both price and all-in capital obviously affect rates of return, generally prices above $60 per barrel yield positive results except where land prices affect profitability significantly. Land prices in the order of $50,000 per acre would require prices of about $80 per barrel to achieve a before tax IRR of 10%
The final element is the cost of capital. In the case of large integrated companies or majors like EOG and Anadarko, the cost of capital is quite low. For the purposes of this argument, I assume that their cost of capital is equal to the higher of the dividend rate or 5%. The same cannot be said for smaller companies. These companies may in some instances have high interest rates exceeding ten percent and usually have strict performance covenants. In the case of producers with under valued stock prices below the net asset value, the cost of new issues could have a much higher cost, sometimes 20% or more. For simplification, let’s generously say its 10%.
Let’s look at the netbacks for a small player with an average all-in land acquisition cost of $15,000 dollars per acre with a type well recovery of 600,000 barrels of oil and 400,000 BOE of gas and liquids. Assume that full cycle capital includes $3.2, $7.0, and $2 million respectively for land purchase, drilling and completion, and facilities. Using year 1 and 2 decline rates of 65% and 30% respectively with a netback before tax of $30 per barrel (implying a WTI price of $56 per barrel), this yields before tax rate of return of 10% and NPV $3.6 million. The most telling economic indicator is time to payout, which in this case is 4.5 years. Using the same parameters and a price of $60 dollars per barrel yields an after-tax rate of return of 10% and an NPV of $3.6 million (interestingly) and a payout is 4.5 years.
Both price and all-in capital obviously affect rates of return, generally prices above $60 per barrel yield positive results except where land prices affect profitability significantly. Land prices in the order of $50,000 per acre would require prices of about $80 per barrel to achieve a before tax IRR of 10%. That said, the most important factor is the rate of decline in the first two years and ultimate recovery. As increasingly poorer wells are drilled and recoveries are lower, the higher the price must be. Infill wells drilled years later will be facing lower reservoir pressure and lower rates and recovery. Once again, companies who drill up each parcel completely (i.e. six wells at once), while managing pressures (i.e. slow back) will have the best economics.
But then of course there are also corporate implications. Smaller companies (smaller than the majors) have many issues. Assuming a cost of capital (debt and issued equity) of 10%, achieving IRR of 10% is not attractive to investors. Another issue is the long periods of payout. At current prices, this means that until enough vintage wells are on stream to offset capital spending, the companies will require continual influx of capital and ultimately drill themselves into oblivion unless prices rise. Well funded companies can overcome this by exploiting high quality reserves.
Large companies are a whole other kettle of fish. They have a lower cost of capital and can fund capital through cash flow. The caveat, is their point of entry (land cost) which is usually later than early adopters. Their primary risk is paying too much for lower quality resources.
To summarize, the winners in this race are those companies who are well funded, have low land costs, are early adopters who have large quantities of superior resource base and have best practices in place for the exploitation of their assets at the lowest costs both capital and operating. Small companies who do not have all the above will ultimately fail absent high prices. Finally, late entry participants (usually the vertically integrated majors) will likely succeed provided they do not pay too much for the assets and do not buy second tier assets.
Randy Evanchuk, P. Eng., has 35 years of experience in the patch. From 2007 until he retired in 2015, Mr. Evanchuk was involved in all phases of of unconventional resource development including;evaluation, economics, production and facilities. As as senior consultant with Murphy’s Holdings, he evaluated their Montney holding as well was as a member of evaluation team. Mr. Evanchuk was the Vice President of new ventures at Daylight Energy where his team was successful in acquiring a substantial Duvernay position. At Seven Generations Energy he was Executive Vice President looking after facilities, marketing, production operations and long range facility and marketing planning.