August 2017 – update
This page describes the input data for a financial simulation model. The model calculates all kinds of financial metrics for each year of the assumed life of a well (30 years) and derives a.o. the required WTI oil price for targeted internal return rates (IRR) of an average tight (shale) oil well.
The input data relate to the 2 major US tight oil plays, The Bakken and the Permian. All costs and revenues are in real 2014-2017 US$.
Peak month production, short term and long term decline curves
For the Bakken, the average peak month oil production data (IP30) and the average decline curve of horizontal wells are derived from a database containing monthly production data for each Bakken well, based on official NDIC data. For the analysis of the peak month data, see here. Because some wells are only reaching their peak production after 6+ months, final determination of IP30 values is a lagging indicator. For 2014, the average IP30 of all wells was 559 bopd (barrel of oil per day). For the first half of 2016, the IP30 data have been readjusted from 631 bopd to 638 bobd. For the full year 2016, IP30 currently stands at 689 bopd.
For the 2014 wells, the long term decline profile is described here. For the 2016 wells, a similar profile is assumed. For the recovery phase (after 2017) , a 3 % reduction of IP30 from the 2016 numbers, to reflect low grading and exhaustion of sweet spots, and a 2% reduction of the first year IP30 multiple, to reflect the expected trend to a slightly steepening well production decline curve, are taken into account.
The shape and IP30 value of the average Permian well has been derived here. Final Permian data lag Bakken Data. It seems that the performance of the average Permian well has become very similar to that of the e Bakken well performance in 2016.
Starting with the 3th production year, the y/y decline rates of oil production (not boe production!) of the Bakken and Permian wells are supposed to be identical.
The natural gas production and retained prices refer to raw/wet/rich natural gas at the bore.
The average initial natural gas (NG) to oil ratio (GOR) of new Bakken wells was 22.5% in 2014 (NG as a % of boe was 18.6%) . The same ratio has been retained for later years. Based on Bakken data of 20 to 30 year old wells, the simulation model assumes that the ratio increases over the life of the well and reaches close to 100% in year 30.
The initial average GOR of the average Permian well has been close to 34% in recent years. As historical data show, Permian GOR tends to increase much faster than that of Bakken wells, typically reaching 100% after 5-6 years and assumed to reach 320% at the end of the well life. That GOR curve is applied in the model.
For the GOR trends, see also here.
Pre peak production
For the Bakken case, 70% of IP30 production was added to the first production year (starting with he IP30 month) to take account of the observed total average pre-peak month production. For the Permian, that number is 55%.
Close to zero information can be found in company filings about royalty rates. The financial data in the filings reflect company owned production data.
The model assumes 20% royalties for the Bakken. That was apparently the low end for wells drilled in the Bakken in 2014. For the Permian, higher royalty rates are common and a rate of 25% has been retained.
Average D&C costs data vary from source source. Even company information is not consistent. In 2014, EOG said that its average D&C costs per Bakken well was around $ 9.5 M. In a 2016 presentation, the average 2014 D&C costs was given with $ 8.8 M. Several companies own to various degrees production factors, like sand mines, chemical manufacturing, drilling and completion services. The resulting D&C cost depend on the profitability allocated to these production factors (does a production factor get an IRR of 15% or only a zero equity cost allocation ?)
The retained estimates represent best guesses, based on company information and published independent studies.
Regarding the Bakken, for 2014 an average well cost of $ 8.2 M has been retained (the reported cost range was from $ 7.2 M to $ 12M), for 2016 an average cost of $ 6 M is used, with costs between $ 5 M and $ 7 M being reported. For 2017 a cost increase is assumed, due to the reported strong recovery of fracking unit costs,the higher ratio of enhanced completions with higher proppant volumes.
Permian oil wells tend to have 20% to 25% shorter laterals than Bakken wells on average, with Delaware wells shorter than Midland wells. By contrast, drilling costs and completion cost per ft are higher. With reference to published IHS data, one can deduct that for 2016, Delaware well costs have been 7% lower than Bakken well costs while Midland well costs have been 20% higher. The retained D&C cost for the average Permian well is thus 8% higher than that of the Bakken well.
Cost increase in 2017 and later. 2016 costs represent the bottom of the cycle.In the first half, fracking costs started to increase strongly from bottom levels. Because Permian’s higher fracking and proppant intensity per ft, Permian wells are likely to see higher completion cost increases.
Currently, the average D&C cost estimate for the Bakken is $ 7.5 M and for the Permian $ 8.5 M. That will still leave the costs significantly below 2014 average D&C costs and could be too low for the 2018 situation.
– Facilities and lifting costs
Generally, facilities are shared among the wells of a pad.Very few companies single out these costs. Qep, which has one of the highest well densities per space unit in the Bakken, has specified its facilities and lifting costs/well for 2016 with $ 0.8 M for it’s compact Antelope acreage and $ 1.3 M for its more dispersed acreage in the Fort Berthold area. Such a more dispersed acreage is quite typical for the average producer in the Bakken.
The retained facilities and lifting cost for the average 2016 and 2017 Bakken well of $ 1 M could therefore be on the low side.
With the trend to more wells per space unit in the Permian, $ 0.7 M/well has been retained for the average Permian well.
– Land leases/Mineral rights
Land leases/Mineral rights are tradable assets. They are consumed/depleted through well investments and are a cost component of each well.
Land lease investments usually constitute a significant part of book value. They are also the basis of the stated reserves, justifying the market value of the company.
Among the major relative pure Bakken players, Whiting Petroleum offers a few data. Whiting’s land acquisitions in 2014 and earlier suggest acre costs between $ 10000 and $ 15000. Whiting’s well productivity in 2014 was average, implying that the cost/acre were average too. After important impairment charges, the leasehold costs relative to net acres amount to an average price per acre between $ 6000 and $ 7000 (core and non core) in 2016. Whiting mentioned that drilling and completions in 2016 were focussed on its most productive properties, suggesting a higher than average acre cost for these wells.Whiting’s top acres are worth more than $ 15000.
Oasis Petroleum made a major leasehold acquisition in 2016, valuing an acre around $ 14000.
In that context, the retained leasehold cost of $ 8000/acre for the 2016 Bakken well seems to be reasonable. The same value, has been retained for the wells of the other years. With that cost, the required WTI price to achieve an IRR between 10% and 15% was close to the effective WTI price until the 4th quarter of 2014, suggesting that $ 8000/acre was near the average fair market price in 2014, although the average book value per acre could have been different.
The typical Bakken space unit is 2 sqm. A typical target well density seem to be 8 wells per space unit. Oasis Petroleum for example has a net acreage of rounded 500000 acres and plans to drill 2870 wells (location inventory+ already drilled wells) in that area.
With an assumed end density of 8 wells per space, the resulting leasehold cost per well amounts to $ 1.28 M. That’s the retained number for the calculations. It has to be said that an 8 wells average per space unit is a high estimate because many low yielding space units will probably not see more than 2 wells unless oil trades far above $ 100/b.
The retained well production decline curve is based on a much lower well density. In 2016 and 2107, drilling was and is generally limited to the companies’ core acreages, which tend to have much higher productivity than non core acreage. Oasis Petroleum estimates that productivity of its non core acreage is less than 40% of its core acreage. For its core+ extended core acreage (average productivity 75% of core), Oasis paid a rounded $12000/acre, which suggests that for Oasis core acreage, used in 2016 and later , much higher acre costs have to be assumed.
A small part of Bakken space units have sizes of 1 sqm. Most of them happen to cover high productive fields like Parshall with significantly above average acre costs. The Leasehold cost per well is therefore not lower in these cases.
For the Permian, 7 or more stacks are considered as exploitable, allthoug currently, exploitation is limited to the 2 or 3 most productive stacks. Test drilling in all the stacks show that the IP30 difference between the 2 or 3 best stacks and the 2 or 3 worst stacks can amount to a factor 2. Therefore, from the median transaction price of $ 30000/acre in 2016, $20000 is supposed to get allocated to the 3 to 4 best stacks, which are the basis of the observed and retained Permian well production curve. To preserve that well productivity level, spacing between wells should not go significantly below currently observed practices, which would limit the number of wells drilled in these 3 to 4 stacks to approximately 16. Tighter spacing would probably lead to lower well performance.
With an estimated average size per spacing unit of 1.7 sqm, the resulting leasehold costs per well amount to $ 1.36 M.
The operating costs are expressed in $/boe.
The companies’ reported cost data per barrel are for portfolios of wells of different ages. They can therefore be considered as a good representation of the average cost of a well over several years of production.
Regarding the Bakken, the cost data for 2014 were mostly derived from the data provided by the following 9 companies, relatively pure Bakken operators, by assigning a higher weighting to the larger companies.
Annual Revenues < US$ 400M in 2014: Abraxas (AXAS), Emerald (EOX), Lonestar (LNREF), American Eagle (AMZG). Annual Revenues > US$ 400M in 2014: Continental Resources (CLR), Whiting Petroleum (WLL), Halcon (HKRCP), Clayton Williams (CWEI), Oasis Petroleum (OAS)
As a result of the oil price crash and the disappearance of smaller operators after 2014, the data for later years also include major operators which are not exclusively focussed on the Bakken play. These companies usually do not provide Bakken specific operating costs. The average costs in these cases are based on the cost of relatively pure Bakken producers.
– Production costs
The production costs comprise LOE, exploration, gathering and local transportation.
For the smaller Bakken companies, the unweighted average in 2014 was $ 14/boe. The retained cost for 2014 of $ 10.6/boe reflect the weight of the large players. For 2016 and later, the Bakken average is estimated at $ 8/boe.
For the Permian wells, the 2016 estimates are somewhat lower – around $ 6.7/boe. One reason is the higher NG content.
– G&A costs
In 2014, the unweighted average G&A costs of the major Bakken companies was $ 5.5/ boe. G&A of the smaller companies was $ 10.3 boe. That was nearly double the cost of the major companies. For 2014, the values of the major companies are used. For 2016, and later, an average value of $ 4.5/boe is retained for Bakken and Permian wells.
– Production taxes
Bakken production taxes oscillate around 9% of revenues for the observed companies. Permian production taxes are more variable. The estimated average is 7.5%.
Cost of Capital
Cost of capital is the weighted average of after tax cost of debt and cost of equity. The same average costs are assumed for Bakken and Permian. The cost exclude the inflation component, included in market rates.
Cost of debt
Cost of debt varies widely from operator to operator. The estimated average cost of 5 year debt, based on maturity adjusted bond yields, has been retained. In 2014, yield and risk premiums were at historical lows. but a multitude of small players with higher risk premiums were present. In 2016, bond yields of the major players have fluctuated widely and were somewhat higher on average, compared with 2014. But, the absence of new wells from small players with higher risk premiums in 2016 has compensated for that. Therefore, the same cost of debt have been retained for both years. The parent companies of several large players like XTO, Burlington/Conocco, Marathon, Statoil have very low debt cost. That impacts the averages. As a result, an average rate of 5% (real) has been retained for 2014 and 2016, based on 5 year maturities.
For later years, an increased base rate, somewhat lower risk premiums for the major players and the re-apparition of small players with higher risk premiums is supposed to result in a 0.8% higher average real interest rate.
Cost of equity
The cost of equity is the discount rate applicable to free cash flow to determine the break even costs.
Compared to debt, equity capital typically carries a higher risk premium because equity is wiped out first in case of financial problems. Its cost is based on theoretical and empirical factors.
For 2014, the calculated cost of equity of the E&P industry was 9.45%/y (including a medium term implied inflation rate of 1.5%). The calculation was based on the CAPM model (basis: 10 year treasury rate of 2.17%, global weighted average risk premium for equity of 5.75% and sector beta of 1.27 for 392 companies), performed by A. Damodaran. For 2016, the real cost of equity was 0.85% higher, according to Damodaran.
It’s assumed that after 2016, volatility and risk premiums will decrease slightly but the base rate (rate of risk free bonds) will increase, resulting in a rate of 9%.
Debt to Capital ratio
The unweighted average net debt/capital ratio for the major independent operators focussed on the Bakken was close to 0.5 at the end of 2014. For the smaller companies, it was somewhat lower. By taking into account the operators which are subsidiaries of larger energy companies (like XTO), using their parent companies’ debt to capital ratios, the average debt to capital ratio falls to 42%. Several pure tight oil operators had to issue new equity to maintain their ratios.
The average ratio of 0.42 is retained for the Bakken and the Permian.
– Depreciation/Depletion of well investment and Leasehold/mineral rights follows the boe production curve. A well life of 30 years is assumed. Some companies calculate with lives of 50 years to boost EUR (Estimated Ultimate Recovery) numbers. Economically, that doesn’t make a difference.
– The initial debt to capital ratio is maintained over the life of the well.
– Discount to WTI : For the Bakken, a discount to WTI of $ 10/b is assumed for 2014, reduced to $ 8/b in 2016 and $ 7/b thereafter. For the Permian, $ 4/b is assumed.
– Natural Gas The model assumes a price received at the well bore (for raw gas) of S$ 4 per Mcf for 2014 wells, $ 2.75 per Mcf for 2016 wells and $ 3 per Mcf for later year wells.
Break even and economic return criteria
The main break even criteria implies that the equity investment is recovered over the lifetime of the well. That is achieved when the sum of discounted annual free cash-flows equals the initial equity investment. The discount rate to apply corresponds to the cost of equity rate. Some research companies apply different, always the same, rates, for example Rystad 7.5%, MBO Capital 10%.
A discount rate or IRR based on free cash flow is not equivalent with PV-10, or the 10% discount rate used in the industry. The PV-10 is not based on free cash flow: certain cost, notably GA and debt costs or debt amortization are not taken into account.
In past years, the investment case in the energy industry generally required an IRR of 15%.
The IRR=0% case is corresponds to the zero return on equity case. For the full cost calculation, it’s quite similar to to the GAAP break even situation.
Marginal/Incremental/Half cycle vs. full costs calculation
Shale oil producers or, more generally speaking, tight oil producers, avoid talking about full costs of the produced oil. Break even or IRR numbers communicated to investors are generally based on partial costs, although that’s usually not mentioned. There is no common standard regarding the costs excluded. Sometimes, the included costs are labelled “half cycle” costs (in contrast to the real – full cycle- costs) or incremental cost. In extreme cases, only cash costs or lifting costs are considered as break even costs. Occasionally, the cost of equity is set to zero.
A definition applied by Raymond James (RJ) is retained here: compared to full costs, costs of mineral rights, G&A, facilities, interest expenses and certain components of production costs are not taken into account.
Full cycle costs include all costs. A company that intends to stay in business without requiring recurring new capital infusions and earn its cost of equity needs to cover its full cycle costs.
Quite often, to show how profitable tight oil is, tight oil profitability based on partial costs is compared to full costs of non tight oil sources. RJ, in a cost comparison study in 2016 acknowledged that openly and justified it as common practice.
Summary of Bakken input data
|Peak month production oil – IP30 (bopd)||560|
|Pre peak month prod (% IP30 month)||70||70||70||55||55|
|IP30 muliple -1st year||5.23||5.23||5.15||5.15||5.15|
|2nd year decline y/y (%)||57||57||57||58||58|
|Gas price raw (US $/Mcf)||4||2.75||3||2.75||3|
|Crude Discount WTI – Wellhead (US $/bo)||10||8||7||4||4|
|Initial gas/ boe (%)||18.5||18.5||18.5||25.5||25.5|
|Gas sold (%)||80||85||90||95||95|
|Investment per well
|D&C (1000 US $)||8200||6000||7500||6500||8400|
|Facilities, lifting (1000 US $)||1100||1000||1000||700||700|
|Leasehold (1000 US $)||1280||1280||1280||1360||1360|
|Cost of equity (%)||8||8.8||9||8.8||9|
|Interest rate debt (%)||5||5.8||5||5.8||5.8|
|Production costs (US $/boe)||10.6||8||8||6.7||6.7|
|G&A (US $/boe)||5.5||4.5||4.5||4.5||3.7|
|Production taxes (% Rev)||9||9||9||7.5||7.5|
|Income taxes (% income)||35||35||35||35||35|
It has to be reminded that those data stand for the average well. Cost data and the decline curve of individual wells can deviate significantly from the statistical average.