Pioneer Natural Resources Company (NYSE:PXD) claimed during its second quarter earnings call that "the horizontal well operating cost excluding taxes is down to almost $2 per BOE". This "very forward-looking statement" needs to be taken with a pinch of salt and several caveats. Pioneer's production derives from multiple fields. Within the Permian Basin, it is only the horizontal wells that boast the $2.25 per barrel of oil equivalent ((Boe)) level of "production costs ex taxes". Such wells account for less than half of the firm's second quarter production. The main objective of this article is to analyze production trends in the various basins and fields, construct a forecast for future production and for the total company production cost per Boe and estimate the time frame for the production cost ex taxes declining to below $3/Boe. The second objective is to point out that the cash available for investment is far less than the Pioneer-stated "cash margin".
The $2 "production cost" figure comes from slide 18 in Pioneer's Q2 earnings presentation:
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Source: Pioneer Natural Resources. The $2.25/Boe focus number is circled.
There have been multiple news articles, starting with this figure as the premise and going on to parrot the claim of being competitive on price with Saudi Arabia. The facts, according to the above image itself, are quite different. Pioneer's production comes from both horizontal and vertical wells in the Permian Basin, with Permian Verticals having a dramatically higher production cost than Permian Horizontals, as well as from Eagle Ford and "Other Assets", which include the Raton Basin, Texas West Panhandle, other areas in south Texas and still other miscellaneous locations. Production costs in all of these fields are $9.80/Boe or above.
Growth in the Permian, other fields in legacy decline
Production from Spraberry/Wolfcamp in the Permian Basin, shown as the red line with an uptrend, is several times as large as contributions from all other fields and is plotted according to the right axis. Data for all other fields are plotted according to the left axis. Production from the Permian will be addressed somewhat later.
New drilling in the Raton Basin and South Texas stopped by or before the end of 2014 as CapEx was directed elsewhere, so the two respective series of production figures show steady declines. There has been new drilling in Eagle Ford and perhaps in the West Panhandle in 2015, which is why the respective lines show production bursts in 2015. In 2016, all CapEx is being directed to the Permian, hence there are declines indicative of legacy production being seen in Eagle Ford and the West Panhandle.
Model assumptions and the resulting forecasts
To model production, constant percentage declines will be assumed for non-Permian production according to the above chart. Estimating decline rates is notoriously difficult. For Eagle Ford, I see a 10% quarterly decline to be a good fit to Pioneer's figures, whereas other fields will be modeled at 5.3% quarterly decline rate. In comparison, EIA's "Drilling Productivity Report" shows a 7.4% month-on-month decline in legacy production in Eagle Ford. This would imply a much higher quarterly decline. I see Pioneer's wells being older than EIA average in Eagle Ford as a plausible explanation for Pioneer showing a much lower decline rate. For any given collection of wells, the decline of the total output depends significantly on how many new or recent wells are present. Pioneer's wells are probably older, as the company has seen better opportunities than continuing to explore Eagle Ford. On the other hand, EIA's dataset of all wells in Eagle Ford likely includes many new wells. I think using the 10% quarterly decline for Eagle Ford, inferred from Pioneer's own figures is a more prudent choice.
In the Permian Basin, there are both horizontal and vertical wells. The outcome of new horizontal drilling and the lack of investment in new vertical wells is shown in the following exhibit.
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Source: Pioneer Natural Resources
There is a decline trend in the contribution from vertical wells. What is known about it is that 59 MBoe/d were produced in 2015 on average, turning into 56 MBoe/d in Q1 2016 and 52 MBoe/d in the second quarter. It is anyone's guess what the true future decline rate will be. The rate of decline relative to 2015 seems much less than the change between Q1 and Q2. Nonetheless, the working assumption will be to use this change to infer a 7.1% QoQ production decline. This assumption is reasonable, as the 7.1% QoQ decline is right in the middle between Eagle Ford's assumed 10% decline and 5.3% decline assumed for other fields.
Finally, production growth from horizontal wells in the Permian will be modeled based on 34% growth target for the total production in the Permian (inclusive of the declining contribution from vertical wells) and 32.5% midpoint of guidance for production growth in 2017 and in subsequent years, again for both Permian well types in the aggregate.
The resulting forecast includes future production for Permian horizontal wells, and for the vertical wells, as well as for Eagle Ford and other fields. Assuming that the production cost figures remain as stated, $2.25/Boe for Permian Horizontals, $12.35 for Permian Verticals, $9.8 for Eagle Ford and $10.19 for other fields, knowledge of future production results in estimates of the total company production cost. All of these are shown in the exhibit below, first for all quarters in 2016 and 2017, and then annually, for all of five years from 2016 to 2020.
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Source: author's analysis
The current production cost at $6.66/Boe is a far cry from the hand-picked best-of-breed figure of $2.25 for horizontal wells in the Permian. However, production costs can be expected to decline if the company is able to sustain its aggressive growth plans involving Permian Horizontals. If 32.5% annual growth can be sustained all the way to 2020, production costs may decline below $3. This would include more than quadrupling production from Permian Horizontals from 2016 to 2020 - a very ambitious target indeed.
The impact of company-level expenses
It is misleading to focus solely on the lowest available production cost. The higher-cost fields are important for generating free cashflow, which brings up the question of how much "cash margin" is truly available to the company to fund its capital expenditures. The answer is: not at all as much as indicated by the "Cash margin" line of the first exhibit in this article.
The "production cost" of $2.25/Boe for Permian Horizontals or $6.66/Boe company-wide at this time, is said to include "lease operating expense, third-party transportation, workover expense and net natural gas processing cost". So, what does it NOT include, that has to be subtracted from "cash margins" of $30.21 for Permian Horizontals or, more relevantly, from $20.59/Boe company-wide?
There are general and administrative expenses (G&A) at $3.77/Boe and interest payments at $2.64/Boe. Additionally in Q2, there was "Other expense" at $3.16/Boe stemming from "transportation commitment charges, idle drilling and well service equipment charges, losses from vertical integration services, terminated drilling rig charges, impairment of inventory, restructuring charges and others". Pioneer also spent $0.71/Boe in connection with sales of purchased oil and gas as the company had to buy oil and gas from third parties to fulfill transportation commitments. Exploration, as distinct from CapEx, cost $0.85/Boe. Totaling up these extra deductions yields $11.13/Boe. Hence, the actual remaining margin available for CapEx is not $20.59/Boe but rather $9.46/Boe. Just like the production cost can be expected to decline gradually towards the headline number of $2 per barrel, the margin available for CapEx may rise gradually, aiming towards $30.31 less $11.13, that is $19.18/Boe for Permian Horizontals.
The production economics of Pioneer Natural Resources stand out even without exaggeration. The company operates in, and has shifted its full focus to, the lowest cost basin in the US, as it executes an ambitious plan of growing production by drilling only horizontal wells. However, this is not the full picture. The full picture, while good, is nowhere as good. The total company production cost, currently $6.66/Boe is not going to approach $2/Boe in the next year or two. It is indeed going to come under $3/Boe only in the event of non-stop annual growth at 32.5% in the Permian and if so, no earlier than 2020. One can dream, but a dream of more than quadrupling production from Permian Horizontals by 2020 is certainly one of a kind. This would also have to happen in order for a $3/Boe or lower production cost to materialize.
While the potential of lower production costs is enticing, it is also important to keep an eye on the total company economics, especially if the company does not increase its capital base. The margin, available for CapEx, is not the "Cash margin" of $30.21/Boe for Permian Horizontals, and not the lower total company "Cash margin" of $20.59/Boe. After accounting for G&A, interest and various unexciting, but nonetheless incurred expenses, the amount usable for CapEx is $9.46/Boe as of now. It is only in the event of the company growing production very aggressively with Permian Horizontals that the CapEx-usable amount may rise towards the $19.18/Boe.
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