A Revaluation Of Standalone Antero Resources

About: Antero Resources Corporation (AR), Includes: AM
by: Michael Bissell, CFA

Recent decline in share price and deconsolidation with Antero Midstream mandates another look at the fundamentals and a revaluation of the stock.

New disclosures from Antero Resources support valuation of PDP reserves and uncompleted well locations.

Despite a reduction in uncompleted well locations since 2017 in excess of those locations drilled, Antero Resources remains undervalued.


I wrote an article in December of 2017, “Antero Resources: An Undervalued Natural Gas and Gas Liquids Producer”, which provided my valuation of Antero Resources Corporation (AR). At the time, Antero's stock was trading at $17.65 per share, as compared to $7.99 at the close on May 8, 2019. My 2017 valuation, based on company presentations and SEC filings of financial statements, was in the upper $20s per share at $3.00/Mcf natural gas and $54/Bbl oil prices. I believe this decline in share price mandates another look at the fundamentals and a revaluation of the stock.

Antero Resources explores and develops natural gas, natural gas liquids (NGLs) and oil properties in the Appalachia Basin of West Virginia and Ohio. Antero also owns approximately 31% of Antero Midstream (AM), which provides gathering, compression, water handling and treatment services primarily for Antero Resources in the Appalachia Basin.

Source: AR Company Presentation – May 2019

Valuation Model

My valuation of Antero Resources consists of two parts. First, I estimated the net present value after tax discounted at 10% (NPV10-AT) of Antero’s proved, developed and producing (PDP) reserves using information recently provided by Antero. This information included expected yearly decline rates for their PDP production and expected costs associated with lease operations and gathering, compression, processing and transportation (GCPT). I then estimated the NPV10-AT of undeveloped locations, again using information recently provided by Antero. The two results were then summed, net debt deducted, and derivative market values and a water payment expected from Antero Midstream added to arrive at the estimated current value of common shares.

PDP Valuation

I calculated the PDP value by starting with an initial 2019 production rate of 3,213 MMcfe/d and reduced this each year by the decline rates given by Antero Resources in their “AR Howard Weil Conference Presentation” from March of 2019. Although decline rates were only given for the first five years, I assumed they would further reduce to 8% in 2024 and remain at that level through 2038, the final year of my 20-year forecast.

Source: AR Howard Weil Conference Presentation – March 2019

The following images from my valuation spreadsheet show the after-tax cash flows for each year, discounted by 10%, and summed over all years to give the NPV10-AT for the PDP reserves.

The yearly average production rates were calculated by assuming a linear decline through each year at the annual production decline rates given. Yearly revenue was then calculated as the product of the average production rate times the average realized price for the production.

Revenue ($ millions) = Average Production (MMcfe/d) x 365 d/y x Average Realized Price ($/Mcfe) / 1,000

The average realized price for production was factored from the relative percentage of each component of production, which were assumed constant, and each components’ realized price (before any impact from derivatives), which I assumed would vary. The percentages for each component were based on actual 4th quarter 2018 production. The realized price premiums or discounts were obtained from Antero Resources’ “2019 Capital Plan and Guidance” for natural gas and C3+ NGLs and from actual 1st quarter 2019 realized prices for ethane and oil. Both component percentages and realized price premiums or discounts were assumed to remain constant over the life of production and are as follows:


Production %

Realized Price

Natural Gas


Henry Hub + $.175/Mcf




C3+ NGLs





WTI - $7.60/Bbl

In the PDP valuation spreadsheet, I used $65.00/Bbl for WTI, $2.70/Mcf for natural gas, $35.08/Bbl for C3+ NGLs and $.24/gal for ethane, for an average realized price of $3.49/Mcfe.

Cash flows before income taxes were calculated by subtracting production costs from revenues. Production costs of $2.20/Mcfe were obtained from Antero Resources’ “2019 Capital Plan and Guidance” and were assumed to remain constant. Other expenses such as marketing and G&A will be addressed in my valuation of Antero’s undeveloped locations.

Source: AR 2019 Guidance – May 2019

Income taxes were estimated by applying an assumed tax rate of 17.9% against each year’s cash flow before taxes. The tax rate was estimated from the December 31, 2018 SEC standard measure (shown below) by dividing the future income tax expense of $5,505 million by the future net cash flows before income tax of $30,739 million. The resulting after-tax cash flows were then discounted at 10% and summed over 20 years resulting in an NPV10-AT for the PDP reserves of $4,344 million.

Undeveloped Locations Valuation

Antero Resources provided single well economics, including cumulative volume estimates, for various BTU regimes in both the Marcellus and Utica in their “October 2018 Company Presentation”. I used the cumulative volume estimates in ethane rejection, along with the reported liquid percentages for each BTU regime, to estimate annual production for the next 20 years.

Source: Antero Resources October 2018 Company Presentation

Source: Antero Resources October 2018 Company Presentation

Source: Antero Resources October 2018 Company Presentation

Source: Antero Resources October 2018 Company Presentation

Since only gas and oil production were given for each BTU regime and ethane was assumed rejected into the gas stream, C3+ NGL production for the first year was estimated as that required to maintain the liquid percentages given and was assumed to decline at the same rate as oil for future years. Annual total natural gas flows for years 2 through 5 were determined by taking the cumulative gas volume for a given year and subtracting the cumulative volume from the previous year. Annual total gas flows for years 6 through 10 and 11 through 20 were assumed to decline exponentially while meeting cumulative volume totals given for years 10 and 20. Oil flows were handled similarly.

Next, the pre-tax NPV10 for each BTU regime was then calculated based on the assumed production profile. Yearly revenues were calculated using Antero’s long-term, standalone realized gas price premium of $.05/Mcf, oil discount of $5.50/Bbl and C3+ NGL price of 69% of WTI oil. Average 6/30/2018 strip prices used were $2.84/Mcf for gas and $54.71/Bbl for WTI oil. Annual half-cycle direct operating and transportation expenses were then deducted and the resulting cash flows discounted at 10% before subtracting well costs to arrive at an NPV10 value for each BTU regime. The assumed liquid percentages for each regime were then adjusted in order that the calculated NPV10 value for each BTU regime was equal to that published in the “October 2018 Company Presentation”. The results for the four most profitable BTU regimes are shown below.

Applying the same price assumptions of $65.00/Bbl for WTI oil, $35.08/Bbl for C3+ NGLs and $2.70/Mcf for natural gas and their realized price premiums or discounts as were used in the PDP valuation, I calculated annual revenues for the four BTU regimes. The half-cycle NPV10 values for each BTU regime were then calculated by deducting half-cycle production costs of $2.20/Mcfe, discounting at 10%, summing the totals and subtracting well costs. The $2.20/Mcfe production costs include full-cycle GCPT expenses, hence the increase compared to the half-cycle costs used for the single well economics.

Average Marcellus well cost was provided by Antero Resources in their “May 2019 Company Presentation” as $.97 million per 1,000’ of lateral for 2019. Assuming average 11,100’ laterals, as was stated in Antero’s February 13, 2019 press release, Marcellus well costs would be $10.8 million per well. Utica wells were assumed to be 7% more expensive based on 2018 relative costs. Well costs include all pad, facility and flowback water costs.

The resulting NPV10 calculations for each of the four BTU regimes are shown below. Only the first 10 of 20 total years are presented.

The following slide from the “AR Howard Weil Conference Presentation” of March 2019 updates the number of undeveloped well locations for each of Antero’s BTU regimes.

Source: AR Howard Weil Conference Presentation – March 2019

Prior to estimating the discounted net present value for Antero’s undeveloped locations, I needed to assume a sequence for yearly wells drilled and completed per BTU regime. My task was somewhat simplified due to the following from a February 13, 2019 press release:

“Antero's 427 proved undeveloped locations average an estimated 1,247 BTU, with an average lateral length of approximately 11,100 feet.”

Also, the above slide from the Howard Weil presentation shows one drilling rig in operation in the Marcellus Highly Rich Gas/Condensate locations and four rigs in the Marcellus Highly Rich Gas locations. Given the above statement and that Antero only plans to drill and complete wells in the Marcellus during 2019 and with the assumption that they would, all else being equal, want to drill and complete their most profitable wells first, I assumed the following drilling plan for the next 20 years.

The first constraint from the press release statement was that there were only 427 proved undeveloped locations. As it was assumed that Antero would complete 120 wells in 2019, the remaining 307 wells had to be proportioned among the next four years, as by definition, proved reserves are those that will be developed within the next five years. The second constraint from the press release was that the average heat content of the 427 locations would be 1,247 BTU/Mcf. Per the assumed drilling sequence above, the average heat content would be 1,257 BTU/Mcf. The higher value is probably due to the planned wells having a BTU content different than the stated average for their BTU regime. This is supported by the change in percent liquids that were back calculated for each regime. To complete the 20-year projection, I assumed Antero would continue to drill and complete the same number of wells as 2023, or 75 per year, for the remaining 15 years.

The discounted net present value for Antero’s undeveloped locations can now be estimated. For each year in the 20-year horizon, the half-cycle net present value of cash flows from each completed well discounted at 10% is multiplied by the total number of wells to be drilled in that BTU regime and summed over all BTU regimes. It’s important to remember that the half-cycle NPVs do not represent cash flows for that year, but rather half-cycle cash flows for all future years discounted at 10%, less well costs.

As I assumed that ethane production would continue to be produced at a 40,000 Bbl/d rate as forecast for 2019 by Antero, cash flows from make-up ethane production required to compensate for the decline of current ethane production needs to be determined and added to half-cycle NPV values. In their February 13, 2019 press release, Antero reported 4th quarter ethane production equal to 8.8% of total production on a 6 Mcfe/Bbl equivalent basis. Applying this to average annual PDP production for the next 20 years and subtracting from the assumed 40,000 Bbl/d rate gives the production rate required for make-up ethane. As ethane is recovered from the gas stream, the revenue from recovered make-up ethane production must be netted against the lost revenue from an equivalent gas stream. The following formulas makes this conversion for each year:

Make-up C2 Cash Flow ($ millions) = 365 (d/y) * 42 (gal/Bbl) * Make-up C2 Rate (MBbl/d) * C2 Realized Price ($/gal) / 1,000

Cash Flow of Equivalent Gas ($ millions) = 365 (d/y) * 42 (gal/Bbl) * Make-up C2 Rate (MBbl/d) / 26.68 (gal/Mcf) * Gas Realized Price ($/Mcf) / 1,000

Net Added Cash Flow ($ millions) = 365 * 42 * Make-up C2 Rate * (C2 Realized Price – Gas Realized Price / 26.68) / 1,000

The results for the next 20 years are shown below:

I next subtracted G&A and marketing expenses and land capital costs. G&A expenses are those forecast by Antero for 2019 and include an estimated $60 million per year for non-cash compensation expense. Marketing expenses were obtained from the following slide from Antero’s “May 2019 Company Presentation” assuming 3.2 Bcfe/d 2019 production that grows 10% per year. For 2022 and future years, annual marketing expense was assumed to be $32 million. Estimated annual land capital costs of $90 million were obtained from Antero’s 2019 capital plan.

Source: AR Company Presentation – May 2019

Finally, income taxes are deducted assuming a 24.7% rate. This was a “plug” rate required to make the discounted present value of income taxes applied against half-cycle NPVs plus make-up ethane revenue for undeveloped locations completed during the next five years equal to $2,111 million when added to the discounted present value of PDP income taxes. The 2018 10-K for Antero Resources gives $2,111 million as the present value discounted at 10% of the $5,505 future income tax expense from the SEC standard measure. Since these tax figures assumed an SEC mandated constant oil price of $65.66/Bbl and gas price of $3.09/Mcf, these prices were also used to calculate the “plug” tax rate.

The resulting yearly totals are then discounted to present value at 10% to give an NPV10-AT value for the undeveloped well locations.

Total Reserves Valuation

The two components of valuation, the NPV10-AT for the PDP reserves and for the remaining undeveloped locations, are added together to determine an enterprise value for Antero Resources. In addition to these two components, I also added the market value of Antero’s 31% ownership of Antero Midstream at its May 8 closing price of $12.26 of $1942 million, hedge book of $607 million as of December 31, 2018 and an expected $125 million payment due from Antero Midstream as contingent consideration for the delivery of fresh water from 2017 through 2019. I discounted this payment at 10% as it will be delivered at the end of 2019. The second contingent payment of $125 million covering water delivery from 2018 through 2020 is not expected to be earned. Although the market value of Antero’s hedge book will change with natural gas prices, I assumed a constant value. Finally, I subtracted long-term debt of $3,476 as of March 31, 2019 to obtain the market value of Antero Resources’ common shares and divided by 308.8 million diluted shares outstanding to obtain a common stock price of $13.68 per share.

Sensitivity Analysis

In order to determine the sensitivity of our Antero Resources price per share valuations to various assumptions, I varied the following assumed constants:

Natural gas price (assumed constant at $2.70/Mcf)

WTI oil price (assumed constant at $65/Bbl)

C3+ NGLs price (assumed constant at $35.08/Bbl)

Ethane price (assumed constant at $.24/gal)

Discount rate (assumed constant at 10%)


As I mentioned in the introduction, my previous valuation of Antero Resources from December of 2017 was in the upper $20s per share at $3.00/Mcf natural gas and $54/Bbl oil prices. Using the same prices in the current revaluation results in a value of $19.65 per share. So, what happened? One clue can be found by comparing the number of uncompleted well locations in each BTU regime.

As the above total uncompleted wells are from the 3rd quarter of 2017 and the 4th quarter of 2018, part of the delta is due to wells turned inline (TIL) during the interim. For the Marcellus, 166 wells were TIL during the interim, while 35 were TIL in the Utica for a total of 201 wells. This still begs the question as to what happened to the remaining 821 well locations that disappeared. Of primary concern is the large number of missing Marcellus Highly Rich Gas/Condensate uncompleted well locations, as they are the most profitable. Even assuming all 166 wells TIL in the Marcellus were in this BTU regime, there are still 407 unaccounted for.

My best guess as to the causes for the disappearance of 801 well locations is that original well spacing assumptions proved too aggressive and that some marginal 3P locations were found to be uneconomical. Also, it appears that 162 locations were reclassified in the Marcellus from liquid rich to dry gas, while the opposite happened in the Utica.

Despite the large reduction in well locations, my revaluation still has Antero Resources significantly undervalued at current prices given the assumptions published by Antero and my interpretation of them. However, I’m more skeptical of the validity of their assumptions. Also, although my background is engineering and finance, I am not a petroleum engineer and my interpretation of Antero’s published information may be inaccurate and/or incorrect. Comments and/or corrections are welcome from readers.

Disclosure: I am/we are long AR. 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.

Additional disclosure: The author makes no guarantees as to the accuracy of the information presented. This article is for informational and educational purposes only and should not be construed to constitute investment advice. Nothing contained herein shall constitute a solicitation, recommendation or endorsement to buy or sell any security.