Closer Look At ConocoPhillips’ Key Business Drivers

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ConocoPhillips

ConocoPhillips (NYSE:COP) is the world’s largest independent exploration and production company in the oil and gas sector, by proved reserves and annual production. Headquartered in Houston, Texas, the company has operations in 27 countries, generating annual sales revenue of more than $60 billion. Based on the second quarter earnings announcement, we revised our price estimate for ConocoPhillips to $85/share, which is around 12.8x our 2014 full-year adjusted diluted EPS estimate for the company. The valuation of an independent oil and gas company largely depends on a few key business drivers such as hydrocarbon production, proved reserves, cash operating margins, and capital expenditures. In this article, we see how these drivers have been trending for ConocoPhillips over the past few years.

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Hydrocarbon Production

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ConocoPhillips expects to boost its net hydrocarbon production rate from around 1,502,000 barrels of oil equivalent per day (MBOED) in 2013 to 1,900 MBOED by 2017. Since the company’s 2013 base production is expected to decline to around 1,100 MBOED by 2017 due to normal field declines, it effectively plans to add new production of almost 800 MBOED in a period of four years. A large majority of this new production (~50%) is expected to come from the ongoing development of its onshore assets in the Lower 48 states. The company has made some good progress on its plan so far this year. [1]

During the second quarter of this year, ConocoPhillips’ average daily net hydrocarbon production increased by 60 MBOED year-on-year to 1,556 MBOED after adjusting for downtime related variance. Almost 82% of this production growth (49 MBOED) came from its operations in the Lower 48 states of the U.S., where the company is ramping up the development of its onshore assets. ConocoPhillips’ second quarter production from the Lower 48 states at 540 MBOED grew by around 10% y-o-y. Most of this growth came from the development of its acreage in the Eagle Ford and Bakken shale plays. [2]

The Eagle Ford shale is now the largest tight oil play in the U.S. by EIA estimates. Its proved crude oil reserves of 3.4 billion barrels are greater than those of the Bakken Formation of North Dakota. ConocoPhillips plans to invest $3 billion annually in the development of its acreage in the Eagle Ford play and expects to more than double the rate of production from around 119 MBOED in 2013 to over 250 MBOED by 2017. During the most recent reported quarter, the company’s average production rate from the Eagle Ford jumped almost 30% y-o-y to 157 MBOED. [2]

The Bakken Shale Play is located in Eastern Montana and Western North Dakota, as well as parts of Saskatchewan and Manitoba in the Williston Basin. According to latest EIA estimates, the Bakken tight oil play holds 3.2 billion barrels of technically and economically recoverable crude oil. ConocoPhillips plans to invest roughly $1 billion annually in the development of its acreage in the Bakken play and expects to ramp up production rate from around 33 MBOED in 2013 to over 68 MBOED by 2017. During the second quarter, the company’s average production rate from the Bakken stood at 51 MBOED, which was almost 70% higher than the previous year’s quarter. [2]

Proved Reserves

The amount of proved hydrocarbon reserves is an extremely critical metric for any oil and gas exploration and production company. It directly impacts the company’s production growth outlook, as it represents the total quantity of technically and economically recoverable oil and gas reserves owned by the company at a given point in time. ConocoPhillips’ total proved hydrocarbon reserves stood at 8,921 million barrels of oil equivalent at the end of last year. This implies that the company held enough reserves at the end of 2013 to be able to produce oil and gas for the next 15 years at 2013 production rates. [3]

More importantly, ConocoPhillips has reported greater than 100% reserve replacement ratio for the last five years. This shows that the company has been able to consistently grow its reserve base through a successful exploration program. Last year, ConocoPhillips’ reserve replacement ratio stood at 178.8% by our estimates, which implies that the company added 78.8% more proved hydrocarbons reserves to its reserve base than the amount of oil and gas it produced last year. Its average reserve replacement ratio for the last five years has been over 143%. The table below summarizes ConocoPhillips’ proved reserves (in millions of barrels of oil equivalent) and reserve replacement ratio for each of the last five years.

Cash Operating Margins

According to our estimates, ConocoPhillips’ consolidated cash EBITDA margins have increased from around 34.4% in 2011 to 35.6% last year. Most of the increase in the company’s cash operating margins during this period has come from better sales volume-mix, and continuous improvements in drilling and completion cost efficiencies. Over the last four years, the company has been able to achieve drilling and completion cost efficiency improvements of 37% and 41%, respectively, in the development of its acreage in the Eagle Ford tight oil play. A large part of this efficiency improvement can be attributed to the increased use of multi-pad well drilling. ConocoPhillips plans to further reduce its average total cost per well by using multi-well pad drilling technique in 75% of all the wells drilled in the Eagle Ford play this year. [1]

In addition to cost efficiency improvements, ConocoPhillips’ cash operating margins have also been expanding over the past few years because of the continuous improvement in its sales volume-mix, which is primarily being driven by the development of its assets in the Lower 48 states. Liquids (crude oil and natural gas liquids) now represent almost 54% of the total hydrocarbons produced by ConocoPhillips from the Lower 48 states, compared to just over 39% at the end of 2011, and their production has been growing rapidly over the last few quarters. During the second quarter of this year, the company’s crude oil production from the Lower 48 states grew by 30% y-o-y, while total hydrocarbon production from the region increased by just around 10%. [2] This is significant because natural gas volumes in the U.S. are not as lucrative currently owing to lower commodity prices. Last year, ConocoPhillips sold liquids at an average price of over $85 per barrel, while the company realized average price of just around $37 per BOE of natural gas. [3]

Capital Expenditures

ConocoPhillips’ gross annual capital expenditure has increased from just over $11.2 billion in 2011 to more than $15.5 billion in 2013 on increased investments in development and exploration activities. As the company continues to develop its acreage in the U.S. onshore plays at an increasing pace, we expect its 2014 gross capital expenditure to be around of $16 billion as well. However, proceeds from the recently closed sale of upstream business in Nigeria will partly offset its net capital expenditures this year. [3]

Going forward, we believe that along with the growing development of unconventional reserves in the U.S., the company’s upcoming new projects in Europe and Asia-Pacific will drive ConocoPhillips’ gross annual capital expenditure higher in the long run. We currently forecast the company’s annual expenditure on drilling and completing wells, acquisition and exploration of hydrocarbon reserves, floating oil platforms and installing pipelines to grow to over $17 billion in the next couple of years.

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Notes:
  1. Investor Update, conocophillips.com [] []
  2. 2014 Q2 Earnings Call Presentation, conocophillips.com [] [] [] []
  3. ConocoPhillips 10-K SEC Filings, sec.gov [] [] []