Cost Of Bakken Oil - A Transparent Analysis

|
Includes: CLR, COP, EOG, EOX, ERF, HES, HK, MRO, OAS, QEP, SM, TPLM, WLL, WPX, XOM
by: Karl Francis

Summary

Required WTI prices are calculated for incremental and full cycle cost variants, two rates of return on equity and three different years.

Calculation principles are described. The relevant input data, based on empirical observations, are quantified.

2016: required WTI price for break even costs: incremental cost variant $45/b, full cost variant: $69/b. Required WTI for full cost IRR15: $78/b.

Recovery after 2016: required WTI price for break even $79/b, for IRR15 $89/b.

For 2016, the EUR (boe) of the average well is calculated to 544 thousand barrels.

This article could be of interest to shareholders of the following companies, which produce more than 90% of Bakken oil:

Hess (NYSE:HES), Whiting (NYSE:WLL), Continental Resources (NYSE:CLR), XTO Energy (NYSE:XOM) , Oasis Petroleum (NYSE:OAS), Burlington Resources (NYSE:COP), Qep (NYSE:QEP), Statoil(STO), EOG (NYSE:EOG), Marathon oil (NYSE:MRO), SM Energy (NYSE:SM), HRC (NYSE:HK), Newfield Production, Slawson Exploration, WPX Energy (NYSE:WPX), Lime Rock Resources, Petro Hunt, Triangle (NYSEMKT:TPLM), Emerald Oil (NYSEMKT:EOX), Enerplus (NYSE:ERF), Hunt Oil, Zavanna

INPUT DATA

The required WTI prices for the average Bakken lateral well are calculated for the years 2014 (the year before the oil price crash), 2016 (the bottom cycle year) and a recovery phase (late 2017, into 2018) for break even and investment criteria.

Two cost calculation variants are considered: full cycle costs and incremental costs/half cycle costs. The latter, which excludes significant costs, is typically used by producers and analysts and published in the media without mentioning its partial cost character.

On the production side, the input data consist of average IP30 (peak production month) values for all wells (> 2000) in 2014. For 2016, first half year IP30 data are used, as reliable full year IP30 data will not be available before the middle of 2017.

Regarding the IP30 and well production profile indicators from 2014 to 2016 for the Bakken average and 22 Bakken producers, see here.

For the assumed 30 year well production decline rate, see here. This curve is based on 2014 Bakken horizontal well data for the first 3 production years, observations about older wells and theoretical studies for the remaining years. For the recovery period, the assumed first year decline rate has been slightly adjusted, based on observed trends.

The model calculates with a continuously increasing gas/oil production ratio (GOR) over the life of the well, based on observations (see here).

All costs are in constant $. Capital costs exclude inflation components.

For a complete presentation and discussion of the input data and assumptions, see here. Selected aspects are presented below in abbreviated form.

Drilling and completion (D&C) costs

The decline in D&C costs has been the main factor in lowering oil costs after 2014, at the expense of service providers. With an expected increase in drilling and fracking activity in the US, these providers will regain pricing power. In the Permian, cost increases of 10% to 20% in recent months are reported, although only drilling, not completions have noticeably increased (the rise in US oil production in the last Q of 2016 was largely coming from the GOM and Alaska, not shale). With completions expected to rise, further costs increases can be expected and are likely to spread to all regions. Down the road, completion cost increases will probably be the main factor driving costs because of the much higher fracking intensity per well, compared to 2014, and capacity constraints.

A 25% D&C cost increase to $ 7.5 M per well is estimated for the recovery phase, with an expected 80% of wells benefiting from enhanced completions. At the same rate of enhanced completions, the average 2014 well would have cost more than $ 9 M in the Bakken. The cost increase might be initiated and driven by the expected supply/demand trends in the Permian.

Land Lease/Mineral rights cost

The retained Land Lease/Mineral rights cost per well are educated guesses, as such information is generally not provided by producers. In the typical incremental cost calculations, these costs are ignored. For 2014, a value of $ 8000/acre has been retained, allocated to the average well on the basis of a target density of 8 wells per 2 sqm space unit.

Many companies have purchased the rights when oil was trading around $ 100/b, often paying more than $10000/acre. The economic value of these rights on the basis of 2016 oil prices was close to zero, but their value in the books of the producers has remained at substantial levels, despite impairment charges.

The land lease costs in the sweet spots, where most of the 2016 drilling occurred, were probably above average, which could imply that the resulting book value depletion was higher than the average acre costs in the books.

Oasis Petroleum purchased a sizable property in the Bakken in 2016, valuing an acre at $ 14000, which suggests that the assumed average mineral rights costs of $ 8000/acre may be conservative.

Break even costs and IRR15

Break even costs are calculated by discounting free cash flow with the cost of equity rate. That rate is empirically determined, based on the data from hundreds of E&P companies, applying the logic of the CAPM model (Damodaran). It was 8% (real) in 2014 and has slowly increased in later years. In the past, the target internal rate of return for investments in the energy sector was typically 15% (IRR15) - the investment benchmark.

Incremental cost vs. full cycle cost accounting

Break even costs of shale oil, presented by companies and analysts to investors are, without specifying it, generally based on partial costs. Several variants are used. Standard approaches are labeled incremental costs, half cycle costs, atror or else. Many media and investors seem to believe that the presented cost numbers represent true full costs. The Raymond James definition of incremental cost calculation is used here. It excludes costs of mineral rights/land leases, facilities, interest, G&A and indirect elements of production costs.

By contrast, full (cycle) cost accounting includes all costs. It gives the true cost of shale oil and it's typically applied to calculate costs outside US shale. It should be applied to compare shale oil costs to oil costs from other sources. A company that intends to stay in business without requiring recurring new capital infusions and earn its cost of equity needs a WTI price corresponding to its full cycle breakeven costs.

Recovery phase

Assumed changes, compared to 2016:

  • Increased drilling causes a partial reversal of the high grading seen in 2016. With enhanced completion now the standard completion method, the related one time IP30 boost will get slowly eroded by saturation effects in the sweet spots.
  • Compared to the 2016 lows, a 25% increase of D&C costs is assumed. With the US shale oil production growth, projected by some analysts, more cost increases would be likely, not reflected in the Recovery scenario.
  • The average well production decline profile is marginally steeper.
  • Received gas prices are assumed to rise slightly, discounts to WTI to fall slightly.
  • Land lease costs, operating costs and G&A cost are supposed to remain at the 2016 levels.

Input data table

Main inputs

2014

2016

Recovery

Revenue factors

IP30 oil (bo/d)

560

630

610

1st year production in IP30 months

5.23

5.23

5.15

2nd year y/y decline rate

57.00%

57.00%

57.00%

Crude discount to WTI ($)

10

8

7

Gas price at well bore -raw -($/Mcf)

4

2.75

3

Natural gas sold %

0.8

0.85

0.90

Natural gas/boe initial ratio

18.5%

18.5%

18.5%

Investments

Mineral Rights ($)

1280000

1280000

1280000

Drilling & Completion ($)

8200000

6000000

7500000

Facilities + Lifting ($)

1100000

1000000

1000000

Capital

Debt/Equity (%)

0.42

0.42

0.42

Interest Rate Debt (% real)

5%

5%

5.8%

Cost of Equity (% real)

8%

8.8%

9%

Operating costs

Production costs ($/boe)

10.6

8

8

G&A ($/boe)

5.5

4.5

4.5

Production tax rate

9%

9%

9%

Income tax rate

35%

35%

35%

RESULTS FOR THE AVERAGE BAKKEN WELL (OIL)

The main results are shown in the following table

Results

2014

2016

Recovery

Incremental cost case ($/bo)

Break even

64

45

52

IRR=15%

75

51

60

Full cost case ($/bo)

Break even

94

69

79

IRR=15%

108

78

89

Full cost case -full equity ($/bo)

Break even

103

77

88

IRR=15%

129

92

107

Production

IP30 (boe/d)

687

774

748

EUR Well (NYSE:BOE)

483

544

518

EUR oil comp. owned sold (1000 boe)

276

311

296

EUR raw NG comp. owned sold (1000 boe)

88

105

106

COMMENTS

Use of debt

The use of debt (at reasonable costs) is an important factor in the determination of the required WTI price, as cost of debt is lower than the cost of equity and tax deductible. In the full cost case without debt (full equity), the required WTI price is $ 10 to $ 20 higher. The following discussion relates to the real world situation with debt.

Full cycle costs

For 2014, the IRR15 case requires $ 108/b WTI oil for the average Bakken well. The break even price is $94/b. WTI prices in the first part of 2014 and in the years before have oscillated in that range.

The required WTI price for IRR15 in 2016 is $ 78/b, break even costs fell to $ 69/b WTI.

In the recovery phase, the required WTI price for IRR15 increases to $ 89/b, break even is at $ 79/b WTI.

Incremental costs

For 2016, the WTI price required for the breakeven case is $ 45/b, for the IRR15 case $ 51/b.

That is within the price range often reported in the media (without specifying that this isn't full costs). The difference per barrel between incremental cost accounting and full cost accounting is in the order of $ 25/b.

IP30 and EUR

The last rows in the Results table show the IP30 for boe (oil+ natural gas) and 3 different EUR (Estimated Ultimate Recovery) numbers for an average well life of 30 years. The "EUR Well " is the number usually presented by companies. It's the total energy produced by an average Bakken well over 30 years. The "EUR company owned, sold" is the amount of oil and NG that the company can monetize for itself.

Income tax rate variation

20% vs. 35%: The required WTI prices are $ 4/b to $ 5/b lower.

Raw gas revenues

The impact of revenues from raw sales on the required WTI price is with $ 4/b to $ 5/b relatively low, although 25% of EUR consists of gas. The reasons are the low price of gas and the slow rise of GOR over time resulting in little economic value when discounted.

Comparison of results with numbers from other sources

Break even calculations and IRR calculations show very different results from source to source. Underlying assumptions are generally not provided. Usually the calculations are based on variants of incremental costs. Full cost calculations are very rare.

In a recent article, Rystad Energy shows 3 graphs. For each graph, break even costs are calculated differently, but always based on variants of partial costs. The 2nd graph (Fig 2) shows required WTI break even prices for different formations, based on 2016 costs. For the Bakken, a price of $ 57/b can be observed. In the related calculations, Rystad has excluded land lease costs and applies a discount rate on free cash flow of 7.5%. With these assumptions, the model used here shows the required WTI price for breakeven cost at $ 60/b.

Comparison with Permian oil costs

Preliminary data for average 2016 well production indicate that the average Bakken well produces slightly more oil than the average Permian well, although the gap has narrowed compared to previous years and could have closed in 2016 (see here). Fracking costs per horizontal ft of the average Permian well exceed those of the Bakken well significantly. Despite having a 25% shorter horizontal leg on average, the D&C cost of the average Permian well is a few% higher than the cost of the average Bakken well.

The Permian well's higher natural gas production compensates for that disadvantage in 2016 so that on balance, the required WTI prices in 2016 are quite similar in both plays. The increase in specific fracking costs in the recovery phase could penalize the cost of Permian oil more than that of Bakken oil.

The advantage of the Permian over the Bakken field consists in having more remaining sweet spot capacity.

Oil prices and well completions

In 2013 and 2014, the new well count plateaued near 2000 wells/year, with the return on equity of the average well between breakeven and IRR15 on a full cost basis. That suggests that a return to a really large increase in drilling and completion volumes would require a WTI price in the mid $ 80/b at least.

Lynn Helms of the NDIC and Continental Resources expect Bakken production to remain relatively flat at current levels until the end of 2018. That would require a completions volume increase of 20% above current levels.

With nearly 40% of total oil revenues of a well produced in the first year starting with the peak production month, one could think that companies would wait with drilling and completion activity until WTI recovers to levels guaranteeing good returns. That has not been the case for the big majority of new wells after 2014.

The Schlumberger CEO said in January 2017:

"North America land operators who appear to remain unconstrained by years of negative free cash flow as external funding seems more readily available and the pursuit of shorter-term equity value takes precedence over a full cycle return".

Other reasons to maintain completion levels higher than suggested by economic logic are cash flow needs, regulations requiring a certain level of activity to preserve land lease rights, contracts with service providers or pre sold oil volumes.

Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

Editor's Note: This article covers one or more stocks trading at less than $1 per share and/or with less than a $100 million market cap. Please be aware of the risks associated with these stocks.