- June 19, 2016
- Posted by: Art Berman
- Category: The Petroleum Truth Report
The break-even price for Permian basin tight oil plays is about $61 per barrel (Table 1). That puts Permian plays among the lowest cost significant supply sources in the world. Although that is good news for U.S. tight oil plays, there is a dark side to the story.
Just because tight oil is low-cost compared to other expensive sources of oil doesn’t mean that it is cheap. Nor is it commercial at current oil prices.
The disturbing truth is that the real cost of oil production has doubled since the 1990s. That is very bad news for the global economy. Those who believe that technology is always the answer need to think about that.
Through that lens, Permian basin tight oil plays are the best of a bad, expensive lot.
Not Shale Plays and Not New
The tight oil plays in the Permian basin are not shale plays. Spraberry and Bone Spring reservoirs are mostly sandstones and Wolfcamp reservoirs are mostly limestones.
Nor are they new plays. All have produced oil and gas for decades from vertically drilled wells. Reservoirs are commonly laterally discontinuous and, therefore, had poor well performance. Horizontal drilling and hydraulic fracturing have largely addressed those issues at drilling and completion costs of $6-7 million per well.
Permian Basin Overview
The Permian basin is among the most mature producing areas in the world. It has produced more than 31.5 billion barrels of oil and 112 trillion cubic feet of gas since 1921. Current production is approximately 1.9 million barrels of oil (mmbo) and 6.6 billion cubic feet of gas (bcfg) per day.
The Permian basin is located in west Texas and southeastern New Mexico (Figure 1). It is sub-divided into the Midland basin on the east and the Delaware basin on the west, separated by the Central Basin platform.
The first commercial discovery in the Permian basin was made in 1921 at the Westbrook Field (Figure 1). It was followed in 1926 with the 2 billion barrel (bbo) Yates Field (San Andres & Grayburg reservoirs), the 2.1 bbo Wasson Field (Glorieta and Leonard reservoirs) in 1936, and the 1.5 bbo Slaughter Field (Abo and Clear Fork reservoirs) also in 1936. Reservoirs were chiefly high-quality limestones although the Wasson and Slaughter fields also produced from mixed sandstones and limestones that are equivalent to reservoirs in today’s Bone Springs tight oil play.
The Spraberry Field (1949) was the first discovery whose primary reservoir was among the present tight oil plays (Figure 2). Its ultimate production before horizontal drilling was estimated at 932 mmbo. The field had low recovery efficiency of 8-10% and was only marginally commercial prior to the recent phase of tight oil drilling.
Tight Oil Plays
I evaluated the three main tight oil plays. The Trend Area-Spraberry play is located mostly in the Midland basin while the Wolfcamp and Bone Spring plays are located mainly in the Delaware basin (Figures 1 and 2).
The Wolfcamp play has produced the most oil and gas—205 million barrels of oil equivalent (mmBOE)*—and has the largest number of producing wells, followed by the Trend Area-Spraberry and Bone Spring plays (Table 2). All of the plays produce considerable associated gas and only the Trend Area-Spraberry is technically an oil play. The Wolfcamp and Bone Spring are classified as gas-condensate plays based on liquid yield.
The Bone Spring play is the most commercially attractive of the tight oil plays with an estimated $49 per barrel of oil equivalent (BOE) break-even price for the top 5 operators. The Spraberry play has a break-even price of $55 per BOE for the top 5 operators but considerably higher well density and, therefore, lower long-term potential. Results from the Wolfcamp play are mixed with an average break-even price of $75 per BOE for the top 5 operators but $61 per BOE excluding one operator with poorer well performance.
Trend Area-Spraberry Play
I evaluated the 5 key operators in the Trend Area-Spraberry play with the greatest cumulative production and number of producing wells: Pioneer (PXD), Laredo (LPI), Diamondback (FANG), Apache (APA) and Energen (EGN) (Table 3).
I did standard rate vs. time decline-curve analysis for those operators. The matches with production history were generally good as shown in the examples in Figure 3.
Much of the gas production in the Permian basin is irregular because of periodic flaring so matching gas production history was sometimes difficult. Oil reporting in Texas is by lease rather than by well so there are periodic upward excursions of oil production as new wells on the same lease come on line. For these reasons, I feel that the decline-curve analysis results are probably optimistic.
The average Trend Area-Spraberry well EUR (estimated ultimate recovery) for the 5 operators is approximately 265,000 BOE using an economic value-based conversion of natural gas-to-barrels of oil equivalent of 15-to-1 (Table 4). The break-even oil price for that average EUR is approximately $55 per BOE. Laredo has the best average well performance with a break-even oil price of about $43 per BOE and Apache has the poorest well performance and highest break-even price of almost $92 per BOE.
Economic assumptions are shown in Table 5.
The top 5 producers in the Wolfcamp play are Cimarex (XEC), Anadarko (APC), EOG, Devon (DVN) and EP (EPE) (Table 6).
Examples of decline-curve analysis for this play are shown in Figure 4.
The average Wolfcamp well EUR for the 5 operators is approximately 228,000 BOE (Table 7). The break-even oil price for that average EUR is approximately $75 per BOE. That is because of poor well performance by Devon and EP whose break-even oil prices are more than $100 per BOE.
By eliminating EP from the calculations, the average EUR for the play is approximately 303,000 BOE and the associated break-even price is about $61 per BOE.
Anadarko has the best average well performance with a break-even oil price of about $45 per BOE and EP has the poorest well performance and highest break-even price of almost $177 per BOE.
Economic assumptions are shown above in Table 4.
Bone Spring Play
The top 5 producers in the Bone Spring play are Cabot (COG), Devon (DVN), Cimarex (XEC), Energen (EGN) and Mewbourne (Table 8).
Examples of decline-curve analysis for this play are shown in Figure 5.
The average Bone Spring well EUR for the 5 operators is approximately 294,000 BOE (Table 9). The break-even oil price for that average EUR is approximately $49 per BOE.
Cimarex has the best average well performance with a break-even oil price of about $42 per BOE and Mewbourne has the poorest well performance and highest break-even price of almost $78 per BOE.
Economic assumptions are shown above in Table 4.
Commercial Play Areas
I made EUR maps for the 3 Permian basin tight oil plays using all wells with 12 months of production. I then used the average play EUR to determine commercial cutoffs for $45 and $60 per BOE oil prices using the economic assumptions in Table 4.
Using the calculated EUR-cutoffs for the two oil-price cases, 26% of Permian tight oil place well break even at $45 per BOE, and 40% break even at $60 per BOE price (Table 10).
Current well density was calculated by measuring the mapped area of the $60 commercial area and dividing by the number of producing wells within those polygons. The Wolfcamp has the lowest well density of 1,269 acres per well and, therefore, the most development potential (Table 11). The Bone Spring also has considerable infill potential with 725 acres per well.
The Trend Area-Spraberry has additional development potential but a comparatively lower current well density of 281 acres per well because there are more than 6,000 vertical producing wells within the $60 commercial area defined by horizontal well EUR. These vertical wells have produced 203 MMBOE to date, approximately equal to the 206 MMBOE for all horizontal wells both inside and outside of the commercial area.
Operators routinely stress the large number of potential infill locations in their investor presentations and press releases based on very close well spacing of, for example, 40 acres per well. Although well density is important for determining play life, I doubt that well spacing of much less than 100 acres per well is economically attractive because of potential interference between wells that are drilled horizontally and hydraulically fractured.
Investors should understand that more wells is not better. Superior economics result from drilling the fewest number of wells necessary to optimize production.
Operators also stress the potential for additional potential reservoirs within the same play reservoir. That is undoubtedly true but those are not yet discovered and are, therefore, resources and not reserves of any category based on the SPE Petroleum Resources Management System. If they are so attractive, why haven’t they been drilled and produced already?
Love In The Time of Cholera
Tight oil and shale gas plays emerged at a time of worry and angst about impending resource scarcity and the decline of America as an world energy power. For some, these plays renewed faith in the ingenuity and technology that made America great. Now, there are even widespread delusions about becoming energy-independent and using new-found resources for global political and economic advantage.
Tight oil was a story of bittersweet success because the plays were commercial only at very high oil prices. When prices dropped in 2014, many expected that these plays would collapse. Instead, producers have taken advantage of the lowest oil-field service prices in decades and the plays have emerged as low-cost leaders among important suppliers of the world’s crude oil.
Low oil-field service costs won’t last and neither will the low break-even prices shown in this post. Still, tight oil plays and two of the Permian basin plays in particular, will break-even at lower prices that almost all OPEC producers once fiscal costs are included (Figure 9). The cost to balance a fiscal budget is the equivalent of corporate overhead for a country whose principal source of income is oil.
But just because tight oil is low cost compared to other expensive sources of oil doesn’t mean that it is cheap. Nor is it commercial at current oil prices.
Since 2009, oil has never been more expensive. The average price in real May 2016 dollars is $83 per barrel, the highest in history (Figure 10). This average includes the year of low oil prices in 2009 after The Financial Crisis and the two years since the mid-2014 oil-price collapse.
Even during the period of the oil shocks from 1974 to 1986, real oil prices were far less averaging $68 per barrel. Today’s price of $48 per barrel remains higher than the average real price of $45 since 1950.
Those who believe that Peak Oil is a failed observation do not understand that it was never about running out of oil. Peak Oil was always about running out of cheap oil. That is an indisputable fact.
The Bone Spring and Trend Area-Spraberry plays of the Permian basin are cheaper than any major world source of oil except Kuwait. They are the best of a bad lot.
Gabriel García Márquez’s masterpiece Love In The Time of Cólera is a story of forbidden love. Cholera is, of course, a disease that comes from infected water supplies and can result in prostration from the loss of fluids (Cólera more commonly means anger or rage in Spanish).
Like a disease, the high cost of energy and debt, its corollary, have drained the life from our global economy over the last several decades. The economic benefits anticipated from lower oil prices after the price collapse did not materialize because prices never stayed low enough for long enough.
The period of high oil prices from 1974 to 1986 created great economic distress for most of the world including the United States. Those who want to make America great again recall the economic prosperity of 1987 to 1999 (Reagan-Bush-Clinton years) when real oil prices averaged only $33 per barrel.
The economic problems that lead up to the 2008 Financial Collapse included high oil prices from 2000 through 2008. The massive new debt incurred to remedy that crisis along with even higher oil prices have thwarted a recovery.
Since the 2014 price collapse, monthly oil prices were less than $33 per barrel for only two months in January and February of this year.
Many talk hopefully about renewed drilling now that oil prices are near $50 per barrel. I doubt that prices will stay at $50 but will, instead, follow the 2015-2016 pattern of cyclicity. Prices should trend higher but I don’t expect a major shift to new drilling or a return to the peak production rates of 2014 and early 2015. The industry is wounded and will not heal for many years if ever.
Tight oil may have bought us a few years of abundance but the resulting over-supply, debt and prolonged period of prices below the cost of production have exacted a terrible cost. Under-investment, a damaged service sector, weak oil company balance sheets and a decimated work force practically ensure cripplingly higher prices a few years in the future.
The calamity of our time of cholera is that we cannot escape ever-higher costs of oil production.
*I use a 15 mcf per barrel equivalent conversion based on the price of natural gas and crude oil. The conversion based on energy content is approximately 6:1 and is used by most producers to calculate BOE EUR. The EUR reported by producers are, therefore, higher than those shown in this study especially for plays and wells with high gas-oil ratios.