DEVON ENERGY CORP/DE
Item 1A. Risk Factors
Our business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.
Oil, Gas and NGL Prices are Volatile
Our financial results are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. A significant downward movement of the prices for these commodities could have a material adverse effect on our revenues, operating cash flows and profitability. Such a downward price movement could also have a material adverse effect on our estimated proved reserves, the carrying value of our oil and gas properties, the level of planned drilling activities and future growth. Historically, market prices and our realized prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:
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supply of and consumer demand for oil, gas and NGLs;
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conservation efforts;
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OPEC production levels;
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weather;
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regional pricing differentials;
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differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);
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differing quality and NGL content of gas produced;
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the level of imports and exports of oil, gas and NGLs;
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the price and availability of alternative fuels;
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the overall economic environment; and
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governmental regulations and taxes.
Estimates of Oil, Gas and NGL Reserves are Uncertain
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Our policies and internal controls related to estimating and recording reserves are included in “Items 1 and 2. Business and Properties” of this report.
Discoveries or Acquisitions of Reserves are Needed to Avoid a Material Decline in Reserves and Production
The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase, due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies,
identify additional producing zones in existing wells, secondary or tertiary recovery techniques, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
Future Exploration and Drilling Results are Uncertain and Involve Substantial Costs
Substantial costs are often required to locate and acquire properties and drill exploratory wells. Such activities are subject to numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling and completing wells are often uncertain. In addition, oil and gas properties can become damaged or drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:
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unexpected drilling conditions;
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pressure or irregularities in reservoir formations;
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equipment failures or accidents;
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fires, explosions, blowouts and surface cratering;
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adverse weather conditions;
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lack of access to pipelines or other transportation methods;
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environmental hazards or liabilities; and
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shortages or delays in the availability of services or delivery of equipment.
A significant occurrence of one of these factors could result in a partial or total loss of our investment in a particular property. In addition, drilling activities may not be successful in establishing proved reserves. Such a failure could have an adverse effect on our future results of operations and financial condition. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.
Competition for Leases, Materials, People and Capital Can Be Significant
Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Typically, during times of high or rising commodity prices, drilling and operating costs will also increase. Higher prices will also generally increase the cost to acquire properties. Certain of our competitors have financial and other resources substantially larger than ours. They also may have established strategic long-term positions and relationships in areas in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuels, and the application of government regulations.
Midstream Capacity Constraints and Interruptions Impact Commodity Sales
We rely on midstream facilities and systems to process our natural gas production and to transport our production to downstream markets. Such midstream systems include the systems we operate, as well as systems operated by third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us. Regardless of who operates the midstream systems we rely upon, a portion of our production in any region may be interrupted or shut in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including,
but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third-parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.
Hedging Limits Participation in Commodity Price Increases and Increases Counterparty Credit Risk Exposure
We periodically enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.
Public Policy, Which Includes Laws, Rules and Regulations, Can Change
Our operations are generally subject to federal laws, rules and regulations in the United States and Canada. In addition, we are also subject to the laws and regulations of various states, provinces, tribal and local governments. Pursuant to public policy changes, numerous government departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which require substantial compliance costs and carry substantial penalties for failure to comply. Changes in such public policy have affected, and at times in the future could affect, our operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Existing laws and regulations can also require us to incur substantial costs to maintain regulatory compliance. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, income taxes and climate change as discussed below.
Hydraulic Fracturing - The Bureau of Land Management is considering the possibility of additional regulation of hydraulic fracturing on federal and Indian lands. Currently, regulation of hydraulic fracturing is conducted primarily at the state level through permitting and other compliance requirements. We lease federal and Indian lands and would be affected by the Interior Department proposal if it were to become law.
Income Taxes - We are subject to federal, state, provincial and local income taxes and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. Recently, the United States President and other policy makers have proposed provisions that would, if enacted, make significant changes to United States tax laws applicable to us. The most significant change to our business would eliminate the immediate deduction for intangible drilling and development costs. Such a change could have a material adverse effect on our profitability, financial condition and liquidity.
Climate Change - Policymakers in the United States and Canada are increasingly focusing on whether the emissions of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policymakers at both the United States federal and state levels have introduced legislation and proposed new regulations that are designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. Legislative initiatives and discussions to date have focused
on the development of cap-and-trade and/or carbon tax programs. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs could be relevant to us and our operations in several ways. First, the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. We could therefore be subject to caps, and penalties if emissions exceeded the caps. Second, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases. Therefore, demand for our products could be reduced by imposition of caps and penalties on our customers. Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting from use of our products by our customers. Of overriding significance would be the point of regulation or taxation. Application of caps or taxes on companies such as Devon, based on carbon content of produced oil and gas volumes rather than on consumer emissions, could lead to penalties, fees or tax assessments for which there are no mechanisms to pass them through the distribution and consumption chain where fuel use or conservation choices are made. Moreover, because oil and natural gas are used as chemical feedstocks and not solely as fossil fuel, applying a carbon tax to oil and gas at the production stage would be excessive with respect to actual carbon emissions from petroleum fuels.
Environmental Matters and Costs Can Be Significant
As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.
Insurance Does Not Cover All Risks
Our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development, production, processing and transportation of oil, natural gas and NGLs. Such risks include potential blowouts, cratering, fires, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals. The occurrence of any of these risks could result in environmental pollution, damage to or destruction of our property, equipment and natural resources, injury to people or loss of life. Additionally, for our non-operated properties, we generally depend on the operator for operational safety and regulatory compliance.
To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well control, business interruption and pollution events that are considered sudden and accidental. We also maintain worker’s compensation and employer’s liability insurance. However, our insurance coverage does not provide 100 percent reimbursement of potential losses resulting from these operational hazards. Additionally, insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for certain risks such as political risk, war and terrorism. Our insurance does not cover penalties or fines assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our profitability, financial condition and liquidity.
Limited Control on Properties Operated by Others
Certain of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties, including compliance with environmental, health and safety regulations or the amount of
required future capital expenditures. These limitations and our dependence on the operator and other working interest owners for these properties could result in unexpected future costs and adversely affect our financial condition and results of operations.
Cyber Attacks Targeting Our Systems and Infrastructure May Adversely Impact Our Operations
The oil and gas industry has become increasingly dependent on digital technologies to conduct daily operations. Concurrently, the industry has become the subject of increased levels of cyber attack activity. Cyber attacks often attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption and may be carried out by third parties or insiders. The techniques utilized range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be carried out in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. Although we have not suffered material losses related to cyber attacks, if we were successfully attacked we may incur substantial remediation and other costs or suffer other negative consequences. Finally, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.
Item 1B. Unresolved Staff Comments
We have no unresolved SEC Staff comments that have been outstanding greater than 180 days from December 31, 2013.
Item 3. Legal Proceedings
We are involved in various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the New York Stock Exchange (the “NYSE”). On February 5, 2014, there were 10,893 holders of record of our common stock. The following table sets forth the quarterly high and low sales prices for our common stock as reported by the NYSE during 2013 and 2012, as well as the quarterly dividends per share paid during 2013 and 2012. We began paying regular quarterly cash dividends on our common stock in the second quarter of 1993. We anticipate continuing to pay regular quarterly dividends in the foreseeable future.
Performance Graph
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on Devon’s common stock with the cumulative total returns of the Standard & Poor’s 500 index (“the S&P 500 Index”), the group of companies included in the Crude Petroleum and Natural Gas Standard Industrial Classification code (“the SIC Code”) and a peer group of companies to which we compare our performance. The peer group includes Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy Corporation, ConocoPhillips, Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Occidental Petroleum Corporation, Pioneer Natural Resources Company and Talisman Energy, Inc. The graph was prepared assuming $100 was invested on December 31, 2008 in Devon’s common stock, the S&P 500 Index, the SIC Code and the peer group and dividends have been reinvested subsequent to the initial investment.
The graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
Issuer Purchases of Equity Securities
The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2013. Such purchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting and stock option exercises.
Under the Devon Energy Corporation Incentive Savings Plan (the “Plan”), eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund (the “Stock Fund”), which is administered by an independent trustee. Eligible employees purchased approximately 52,500 shares of our common stock in 2013, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Plan through open-market purchases.
Similarly, under the Devon Canada Corporation Savings Plan (the “Canadian Plan”), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee. Eligible Canadian employees purchased approximately 10,800 shares of our common stock in 2013, at then-prevailing stock prices, that they held through their ownership in the Canadian Plan. We acquired the shares sold under the Canadian Plan through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S.
Item 6. Selected Financial Data
The financial information below should be read in conjunction with “
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.
Overview of 2013 Results
As an enterprise, we strive to optimize value for our shareholders by growing cash flow, earnings, production and reserves, all on a per debt-adjusted share basis. We accomplish this by executing our strategy, which is outlined in “Items 1 and 2. Business and Properties” of this report.
2013 was another year of strong execution and exciting change for Devon. Our oil-focused drilling programs not only accomplished impressive oil production growth, but also expanded margins and improved operating cash flow. Additionally, we took steps to high-grade our portfolio. We did this by announcing an accretive Eagle Ford Shale acquisition, an innovative midstream combination, and the initiation of an asset divestiture program. These actions will provide the platform from which we will deliver outstanding high-margin growth in 2014 and for many years to come.
Key measures of our 2013 performance are summarized below, which exclude amounts from our discontinued operations.
(1) Adjusted earnings, adjusted earnings per share and adjusted operating cash flow are not financial measures prepared in accordance with accounting principles generally accepted in the United States (GAAP). For a description of adjusted earnings, adjusted earnings per share and adjusted operating cash flow as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.
(2) Computed as revenues from commodity sales, commodity derivatives settlements, and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, general and administration, taxes other than income taxes and interest, with the result divided by total production.
(3) Includes common stock dividends and share repurchases.
Our 2013 net loss resulted from noncash asset impairments, which reduced our earnings by $2.0 billion ($1.4 billion after tax). Excluding the asset impairments and other items typically excluded by securities analysts, our adjusted earnings were $1.7 billion, or $4.26 per diluted share. This compares to adjusted earnings of $1.3 billion, or $3.22 per diluted share in 2012.
Our 2013 adjusted earnings, adjusted earnings per share and adjusted operating income per Boe all increased compared to 2012. The improved 2013 results were driven primarily by increases in gas prices, oil volumes and oil realizations. These factors also contributed to higher adjusted operating cash flow, which combined with a reduction in capitalized costs, caused our cash flow deficit to narrow considerably in 2013.
Business and Industry Outlook
North American crude oil and natural gas prices have historically been volatile based on supply and demand dynamics and we expect this volatility to continue into 2014. Although natural gas prices improved in 2013 compared to 2012, natural gas continues to be challenged due to an imbalance between supply and demand across North America. However, arctic air movements across North America during the early weeks of 2014 have caused natural gas demand to surge. As storage inventories have significantly declined in response to the recent weather conditions, natural gas prices have surpassed $5 per Mcf for the first time since the summer of 2010. Further helping demand, new uses of natural gas in industrial, power and other sectors will continue to help support price dynamics. Nevertheless, we still expect natural gas prices to be range-bound as natural gas supply continues to grow, particularly in the U.S. Looking to 2014, we expect natural gas prices will remain relatively consistent or possibly increase moderately from 2013 levels.
Similar to natural gas in recent years, a surge in the supply of natural gas liquids has kept prices challenged. The majority of our natural gas is comprised of ethane, one of the most price-challenged liquids processed from the natural gas stream. We expect 2014 natural gas liquids prices will be range-bound and remain relatively flat compared to 2013.
Crude oil prices remained relatively stable throughout 2013, and oil continues to be more valuable than natural gas on a relative energy-equivalent basis. As a result, we and other producers have been focused on growing oil production. North American crude oil supply continues to increase due to the continued use of horizontal drilling technology throughout the U.S. and expansions of heavy oil production operations primarily in Canada. Global crude oil demand is expected to grow with supply in 2014. As crude oil supply grows, transportation capacity to downstream markets will be increasingly important. Bottlenecks and other transportation limitations may continue to add volatility among U.S. and Canadian grades of oil. However, we expect 2014 oil prices will remain relatively consistent with 2013.
We exited 2013 with a production profile comprised of roughly 55 percent natural gas, 25 percent oil, and 20 percent natural gas liquids. Recognizing the relative value of crude oil, we are devoting the vast majority of our 2014 capital investment toward growing our oil production, particularly the sweet grades of oil found in the U.S. To make a significant shift in our production profile, we expect to complete a $6 billion acquisition of Eagle Ford Shale assets in the first quarter of 2014 and divest non-core, dry natural gas assets throughout 2014. Once these transactions are complete, we expect oil will represent more than 30 percent of our production profile.
Further enhancing the value of our assets, we are combining substantially all of our U.S. midstream assets with Crosstex Energy, Inc.’s and Crosstex Energy, L.P.’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), a master limited partnership and a general partner entity, which will both be publicly traded entities. The new midstream business will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. Devon will own a 70 percent controlling interest in EnLink and an approximate 53 percent controlling interest in the Partnership.
Results of Operations
All amounts in this document related to our International operations are presented as discontinued. Therefore, the production, revenue and expense amounts presented in this “Results of Operations” section exclude amounts related to our International assets unless otherwise noted.
Oil, Gas and NGL Production
Oil, Gas and NGL Pricing
(1) Prices presented exclude any effects due to oil, gas and NGL derivatives.
Commodity Sales
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales.
Volumes 2013 vs. 2012 - Upstream sales increased $625 million due to a 15 percent increase in our liquids production, partially offset by a 7 percent decline in our gas production. Oil production was the largest driver of the increase, accounting for 85 percent of the higher sales. Largely due to continued development of our properties in the Permian Basin, the Mississippian-Woodford Trend and the Anadarko Basin, our oil sales increased $531 million. Bitumen sales increased $65 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $181 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale and the Anadarko Basin. These increases were partially offset by a 7 percent decrease in our 2013 gas production, resulting in a $152 million decline in sales.
Volumes 2012 vs. 2011 - Upstream sales increased $695 million due to a 4 percent increase in production. Oil and bitumen production were the largest drivers of the increase, accounting for nearly 90 percent of the higher sales. As a result of continued development of our liquids-rich properties in the Permian Basin, our oil
sales increased $337 million. Bitumen sales increased $273 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $137 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale and the Anadarko Basin. These increases were partially offset by a slight decrease in our 2012 gas production, resulting in a $52 million decline in sales.
Prices 2013 vs. 2012 - Upstream sales increased $744 million due to an 18 percent increase in our realized price without hedges. Our gas sales were the most significantly impacted with a $639 million increase in sales. The change in our gas price was largely due to higher North American regional index prices upon which our gas sales are based. Our liquid sales increased $105 million due to higher oil and bitumen sales partially offset by lower NGL sales. The largest contributors to the higher liquids prices were an increase in the average NYMEX West Texas Intermediate index price and a slightly higher bitumen realized price, partially offset by lower NGL prices at the Mont Belvieu, Texas hub.
Prices 2012 vs. 2011 - Upstream sales decreased $1.9 billion due to a 17 percent decrease in our realized price without hedges. Our gas sales were the most significantly impacted with a $1.1 billion decrease in sales. The change in our gas price was largely due to fluctuations of the North American regional index prices upon which our gas sales are based. We also experienced declines in our NGL, bitumen and oil sales due to our realized price. The largest contributors to the lower liquids prices were lower NGL prices at the Mont Belvieu, Texas hub and wider bitumen differentials.
Oil, Gas and NGL Derivatives
The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and fair value gains and losses recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.
Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments. A summary of our open commodity derivative positions is included in Note 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Our oil, gas and NGL derivatives include price swaps, costless collars, basis swaps and call options. To facilitate a portion of our price swaps, we sold gas and oil call options for 2014 through 2016. The call options give counterparties the right to purchase production at a predetermined price.
In addition to cash settlements, we also recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred net losses of $191 million in 2013 and generated net gains of $693 million and $881 million during 2012 and 2011, respectively.
Marketing and Midstream Revenues and Operating Costs and Expenses
2013 vs. 2012 Marketing and midstream operating profit increased $104 million, or 25 percent, from the year ended December 31, 2012 to the year ended December 31, 2013.
Our profit largely increased due to the effects of pricing and marketing activities. Our profit increased nearly $40 million due to our NGL and gas marketing. Additionally, changes in pricing led to an increase in operating profit of approximately $32 million. Higher residue natural gas prices were the primary contributor to the higher profit.
Higher gathering and processing volumes were responsible for an increase in operating profit of $21 million. Higher volumes were primarily the result of NGL production. The increase was largely driven by higher inlet volumes at the Cana processing facility, improved efficiencies at the Cana and Bridgeport processing facilities and downtime impacting our Bridgeport processing facility in 2012.
Operations and maintenance expenses decreased $11 million, or 6 percent primarily due to expenditures for regulatory testing in 2012.
2012 vs. 2011 Marketing and midstream operating profit decreased $124 million, or 23 percent, from the year ended December 31, 2011 to the year ended December 31, 2012.
Our profit largely decreased due to the effects of pricing and marketing activities. Changes in pricing led to a decrease in operating profit of approximately $106 million. Lower residue natural gas and NGL prices were the primary contributor to the lower profit. Additionally, our profit decreased $13 million primarily due to lower profits on our NGL marketing.
Higher gathering, processing and transportation volumes were responsible for an increase in operating profit of $11 million. Higher volumes were primarily the result of additional throughput at Bridgeport and Cana gathering.
Operations and maintenance expenses increased $16 million, or 9 percent primarily due to expenditures for regulatory testing in 2012.
Lease Operating Expenses (“LOE”)
2013 vs. 2012 LOE increased $0.67 per Boe largely because of our liquids production growth, particularly in the Permian Basin and the Mississippian-Woodford Trend in the U.S. These projects generally require a higher per unit cost than our gas projects, particularly because they are in the early stages of development. Additionally, we conducted a turnaround at Jackfish 2 in the third quarter of 2013, contributing to higher unit costs in 2013. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.
2012 vs. 2011 LOE increased $0.59 per Boe largely because of our oil production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian Basin in the U.S. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.
General and Administrative Expenses (“G&A”)
2013 vs. 2012 Net G&A and net G&A per Boe decreased largely due to lower personnel expenses and office rent as a result of the Houston office consolidation in 2012 and lower costs as a result of the company-wide implementation of SAP in Q2 2012. Higher reimbursements due to increased liquids drilling activity and reimbursement rates also contributed to the decrease in net G&A and net G&A per Boe.
2012 vs. 2011 Net G&A and net G&A per Boe increased largely due to higher employee compensation and benefits. Employee costs increased primarily from an expansion of our workforce as part of growing production operations at certain of our key areas, including Jackfish, the Permian Basin and the Anadarko Basin.
Production and Property Taxes
2013 vs. 2012 Production and property taxes increased primarily due to an increase in our U.S. revenues, on which the majority of our production taxes are assessed.
2012 vs. 2011 Production and property taxes decreased primarily due to a decrease in our U.S. revenues, on which the majority of our production taxes are assessed.
Depreciation, Depletion and Amortization (“DD&A”)
A description of how DD&A of our oil and gas properties is calculated is included in Note 1 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, when the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes.
2013 vs. 2012 Oil and gas property DD&A decreased $61 million largely as a result of the asset impairment charges recognized in 2012 and 2013. Depreciation and amortization on our other properties increased $30 million largely from the construction of our new headquarters in Oklahoma City and natural gas pipeline development in the Cana-Woodford Shale.
2012 vs. 2011 Oil and gas property DD&A increased $460 million due to a 22 percent increase in the DD&A rate and $79 million due to our 4 percent increase in production. The largest contributors to the higher rate were our 2012 drilling and development activities.
Asset Impairments
Oil and Gas Impairments
Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1 to the financial statements under “Item 8. Consolidated Financial Statements” of this report.
The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which have reduced proved reserve values.
Midstream Impairments
Due to declining natural gas production resulting from low natural gas and NGL prices, we determined that the carrying amounts of certain of our midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.
Net Financing Costs
2013 vs. 2012 Net financing costs increased primarily due to additional debt borrowings and associated fees, partially offset by lower weighted average interest rates and higher capitalized interest. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and to provide funding for our planned Eagle Ford Shale acquisition that is expected to close in the first quarter of 2014.
2012 vs. 2011 Net financing costs increased primarily due to additional debt borrowings and lower capitalized interest, partially offset by lower weighted average interest rates. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and divestiture proceeds.
Restructuring Costs
(1) Restructuring costs related to our discontinued operations totaled $(2) million in 2011. These costs primarily consist of employee severance and are not included in the table. There were no costs related to discontinued operations in 2013 or 2012.
Office Consolidation
In October 2012, we announced plans to consolidate our U.S. personnel into a single operations group centrally located at our corporate headquarters in Oklahoma City. As a result, we closed our office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation.
Employee severance and retention - As of December 31, 2013, we had incurred $90 million of employee severance and retention costs associated with the office consolidation. This included amounts related to cash severance costs and accelerated vesting of share-based grants.
Lease obligations and other - As of December 31, 2013, we had incurred $28 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that we ceased using as a part of the office consolidation. Our estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that we may receive over the term of the leases, as well as the amount of variable operating costs that we will be required to pay under the leases.
Divestiture of Offshore Assets
In the fourth quarter of 2009, we announced plans to divest our offshore assets. As of December 31, 2012, we had divested all of our U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.
Income Taxes
The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the United States statutory income tax rate.
Pursuant to the completed and planned divestitures of our International assets located outside North America, a portion of our foreign earnings had been deemed to no longer be indefinitely reinvested. As of December 31, 2012, we had recognized a $936 million deferred income tax liability related to assumed repatriations of earnings from our foreign subsidiaries, including $725 million of deferred income tax expense recognized in 2011.
In the second and fourth quarters of 2013, we repatriated to the U. S. a total of $4.3 billion of our cash held outside of the U. S. In the fourth quarter of 2013, we announced plans to divest of our Canadian non-core properties. These events resulted in incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.
In 2013, our state income tax rate is higher than 2012 and 2011 primarily due to the relatively small amount of pre-tax income, resulting from pre-tax income for the U.S. partially offset by a pre-tax loss for Canada. Also, in the table above, the “other” effect is primarily comprised of permanent tax differences for which the dollar amounts do not increase or decrease as our pre-tax earnings do. Generally, such items typically have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate for the years ended December 31, 2013 and 2012, respectively, because of the relatively small pre-tax income/loss for those periods. For 2013 “other” was comprised primarily of tax audit adjustments and a favorable tax impact due to acquisition financing.
Earnings (Loss) From Discontinued Operations
The earnings (loss) in each period were primarily driven by gains (losses) on the sales of our oil and gas assets in each period. In 2012 we incurred a loss of $16 million ($21 million net of taxes) for the sale of our assets in Angola. In 2011 we generated a gain of $2.5 billion ($2.5 billion net of taxes) for the sale of our assets in Brazil.
Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major source and use categories of our cash and cash equivalents.
Operating Cash Flow - Continuing Operations
Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in 2013. Our operating cash flow increased 10 percent during 2013 primarily due to higher commodity prices and production growth, partially offset by higher expenses. Our operating cash flow decreased 21 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth and higher cash settlements from our commodity derivatives.
During 2013 our operating cash flow funded approximately 80 percent of our cash payments for capital expenditures. Leveraging our liquidity, we used cash balances, short-term debt and divestiture proceeds to fund the remainder of our cash-based capital expenditures.
Capital Expenditures
Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $6.0 billion, $7.4 billion and $6.9 billion in 2013, 2012 and 2011, respectively. The 20 percent decline in exploration, development and acquisition capital spending in 2013 was primarily due to a decline in new venture acreage acquisitions and utilization of the drilling carries in 2013 from our Sinopec and Sumitomo joint venture arrangements. The higher exploration and development capital spending in 2012 and 2011 was primarily due to new venture acreage acquisitions and increased drilling and development. With rising oil prices and proceeds from our offshore divestitures, we increased our onshore North American acreage positions and associated exploration and development activities to drive near-term growth of our oil production.
Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil pipelines. Our midstream capital expenditures are largely impacted by oil and gas drilling activities. The higher 2013 midstream expenditures primarily relate to expansions of our plants serving the Barnett Shale and Cana-Woodford Shale and our Access Pipeline transporting heavy oil in Canada.
Capital expenditures related to other activities decreased in 2013. This decrease is largely driven by the construction of our new headquarters in Oklahoma City, which was completed in 2012.
Debt Activity, Net
During 2013, we increased our debt borrowings by $361 million as a result of issuing $2.25 billion of debt related to the planned Eagle Ford Shale acquisition, which is expected to close in the first quarter of 2014, and repaying approximately $1.9 billion of outstanding short-term debt.
In December 2013, to provide funding for our planned Eagle Ford Shale acquisition, we issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes resulting in cash proceeds of approximately $2.2 billion, net of discounts and issuance costs.
During 2012, we increased our debt borrowings by $1.9 billion as a result of issuing $2.5 billion of long-term debt and repaying approximately $0.6 billion of outstanding short-term debt. The additional borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.
During 2011, we increased our commercial paper borrowings by $3.7 billion and received $0.5 billion from new debt issuances, net of debt maturities. Proceeds were primarily used to fund capital expenditures and common stock repurchases in excess of operating cash flow.
Shareholder Distributions
The following table summarizes our share repurchases and our common stock dividends (amounts and shares in millions).
In connection with our offshore divestitures, we conducted a $3.5 billion share repurchase program that we completed in the fourth quarter of 2011. Under the program, we repurchased 49.2 million shares, representing 11 percent of our outstanding shares, at an average price of $71.18 per share.
Divestitures of Property and Equipment
In 2013, we sold our Thunder Creek operations in Wyoming for approximately $148 million and our Bear Paw Basin assets in Havre, Montana for approximately $73 million. We also sold other minor oil and gas assets.
During 2012, we closed joint venture transactions with Sinopec and Sumitomo. Sinopec paid approximately $900 million in cash and received a 33.3 percent interest in five of our new ventures exploration plays in the U.S. Sinopec is also funding approximately $1.6 billion of our share of future exploration, development and drilling costs associated with these plays. Sumitomo paid approximately $400 million and received a 30 percent interest in the Cline and Midland-Wolfcamp Shale plays in Texas. Additionally, Sumitomo is funding approximately $1.0 billion of our share of future exploration, development and drilling costs associated with these plays.
Also in 2012, we sold our West Johnson County Plant and gathering system in north Texas for approximately $90 million and divested our Angola operations for approximately $71 million.
In 2011, our divestitures primarily related to the divestitures of our offshore assets.
Liquidity
Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed in this section, including our planned $6 billion acquisition of Eagle Ford Shale assets from GeoSouthern.
Operating Cash Flow and Cash Balances
Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. Due to higher commodity prices, our operating cash flow from continuing operations increased 10 percent to $5.4 billion in 2013. We expect operating cash flow to continue to be our primary source of liquidity.
Commodity Prices - Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control. We expect this volatility to continue throughout 2014.
To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum prices on our future production. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2013 are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.
Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow. However, the inverse is also generally true during periods of depressed commodity prices or reduced activity.
Interest Rates - Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2013, we had total debt of $12.0 billion with an overall weighted average borrowing rate of 4.1 percent.
Credit Losses - Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. Additionally, we are exposed to the credit risk of counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings.
As recent years indicate, we have a history of investing more than 100 percent of our operating cash flow into capital development activities to grow our company and maximize value for our shareholders. Therefore, negative movements in any of the variables discussed above would not only impact our operating cash flow, but also would likely impact the amount of capital investment we could or would make.
At the end of 2013, we held approximately $6.1 billion of cash. Included in this total was $1.8 billion of cash held by our foreign subsidiaries. If we were to repatriate a portion or all of the cash held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U. S. tax law. The payment of such additional income tax would materially decrease the amount of cash and short-term investments ultimately available to fund our business.
Credit Availability
We have a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that matures on October 24, 2018. Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of December 31, 2013, we had $2.9 billion of available capacity under our syndicated, unsecured Senior Credit Facility, net of letters of credit outstanding.
The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65 percent. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as full cost ceiling impairments. As of December 31, 2013, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2013, as calculated pursuant to the terms of the agreement, was 25.7 percent.
Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.
We also have access to $3.0 billion of short-term credit under our commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2013, we had $1.3 billion of borrowings under our commercial paper program.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Our current debt ratings are BBB with a stable outlook by Fitch, BBB+ with a negative outlook by Standard & Poor’s, and Baa1 with a review for downgrade by Moody’s.
There are no “rating triggers” in any of our debt contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs from LIBOR plus 112.5 basis points to a new rate of LIBOR plus 125 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future.
Capital Expenditures
Excluding our planned $6 billion Eagle Ford Shale acquisition, our 2014 capital expenditures are expected to range from $6.4 billion to $6.9 billion, including $5.4 billion to $5.8 billion for our oil and gas operations, which include capitalized G&A and interest. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from our current estimates, we could choose to defer a portion of these planned 2014 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2014 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2014, our existing commodity hedging contracts, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2014 capital expenditures.
Additionally, our financial and operational flexibility has been further enhanced by the joint venture transactions that we entered into in 2012 with Sinopec and Sumitomo. Pursuant to the joint venture agreements, Sinopec and Sumitomo are subject to drilling carries with remaining commitments that totaled $1.4 billion at the end of 2013. These drilling carries will fund 70 percent of our capital requirements related to joint venture properties, which results in our partners paying approximately 80 percent of the overall development costs during the carry period. This is allowing us to accelerate the de-risking and commercialization of the joint venture properties without diverting capital from our core development projects. We expect the remaining carries will be realized by the end of 2015.
Acquisitions and Divestitures
GeoSouthern Acquisition - On November 20, 2013, we entered into an agreement with GeoSouthern Intermediate Holdings, LLC, to acquire certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford Shale in south Texas for $6 billion in cash. The transaction is expected to close in the first quarter of 2014.
To provide funding for the Eagle Ford Shale acquisition, we issued $2.25 billion of senior notes in December 2013. The floating rate senior notes due in 2015 bear interest at a rate equal to three-month LIBOR plus 0.45%, which rate will be reset quarterly. The floating rate senior notes due in 2016 bear interest at a rate equal to three-month LIBOR plus 0.54%, which rate will be reset quarterly. We also entered into a term loan agreement in December 2013 with a group of major financial institutions pursuant to which we may draw up to $2.0 billion to finance, in part, the Eagle Ford Shale acquisition and to pay transaction costs. Half of any loans under the term loan agreement will have a maturity of three years and the other half will have a maturity of five years (the 5-Year Loans). The 5-Year Loans will provide for the partial amortization of principal during the last
two years that they are outstanding. Loans borrowed under the term loan agreement may, at our election, bear interest at various fixed rate options for periods up to six months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate.
In the event that the Eagle Ford Shale acquisition is not completed on or prior to June 30, 2014, we will be required to redeem each series of new senior notes at 101% of the $2.25 billion aggregate principal amount, plus accrued and unpaid interest.
Crosstex Merger - On October 21, 2013, Devon, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) announced plans to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), a master limited partnership and a general partner entity, which will both be publicly traded entities.
In exchange for a controlling interest in both EnLink and the Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink will each own 50% of EnLink Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval. Devon expects Crosstex Energy, Inc. shareholders will approve the transaction, allowing Devon and Crosstex to complete the transaction near the end of the first quarter of 2014.
Upon closing of the transactions, the pro forma ownership of EnLink will be approximately:
•
70% - Devon Energy Corporation
•
30% - Current Crosstex Energy, Inc. public stockholders
Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:
•
53% - Devon Energy Corporation
•
40% - Current Crosstex Energy, L.P. public unitholders
•
7% - the General Partner
Asset Divestitures - In conjunction with the announcement of the Eagle Ford Shale acquisition, we also announced plans to monetize certain non-core assets located throughout Canada and the U. S. The divestitures will likely occur in a number of separate transactions, but we expect to complete the majority of the divestitures by the end of 2014.
Contractual Obligations
A summary of our contractual obligations as of December 31, 2013, is provided in the following table.
(1) Debt amounts represent scheduled maturities of our debt obligations at December 31, 2013, excluding $20 million of net discounts included in the carrying value of debt. Included in current debt is the $2.25 billion senior notes related to the GeoSouthern acquisition that will be reclassified to long-term once the transaction closes in the first quarter of 2014.
(2) Interest expense represents the scheduled cash payments on long-term, fixed-rate debt and an estimate of our floating-rate debt.
(3) Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.
(4) Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets.
(5) Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2013 balance sheet.
(6) Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.
(7) Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations.
(8) These amounts include $243 million related to uncertain tax positions.
Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 18 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.
Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the
United States of America requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.
Full Cost Method of Accounting and Proved Reserves
Our estimates of proved reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by outside petroleum consultants. In 2013, 91 percent of our reserves were subjected to such audits.
The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than two percent of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
While the quantities of proved reserves require substantial judgment, the associated prices of oil, gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. Applicable rules require future net revenues to be calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Such rules also dictate that a 10 percent discount factor be used. Therefore, the discounted future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs or our enterprise risk.
Because the ceiling calculation dictates the use of prices that are not representative of future prices and requires a 10 percent discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating fair value. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Because of the volatile nature of oil and gas prices, it is not possible to predict the timing or magnitude of full cost write-downs. In addition, due to the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling write-down.
Derivative Financial Instruments
We periodically enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production to hedge future prices received. Our commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.
The estimates of the fair values of our derivative instruments require substantial judgment. We estimate the fair values of our commodity derivative financial instruments primarily by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using United States Treasury bill rates. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.
We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. Under the terms of our interest rate swaps, we generally receive a fixed rate and pay a variable rate on a total notional amount. As of December 31, 2013 we had no outstanding interest rate swaps.
We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest rate yields. The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rates. These yield and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward interest rate yields.
We periodically enter into foreign exchange forward contracts to manage our exposure to fluctuations in exchange rates. Under the terms of our foreign exchange forward contracts, we generally receive U.S. dollars and pay Canadian dollars based on a total notional amount.
We estimate the fair values of our foreign exchange forward contracts primarily by using internal discounted cash flow calculations based upon forward exchange rates. The most significant variable to our cash flow calculations is our observation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturity of the contracts are discounted using Treasury rates. These discounting variables are sensitive to the period of the contract and market volatility.
We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties.
Counterparty credit risk has not had a significant effect on our cash flow calculations and derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with fourteen separate counterparties, and our foreign exchange forward contracts are held with four separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold for collateral posting decreases as the debt rating falls further below such credit levels.
Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.
Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding
the effects that changes in market prices can have on our derivative financial instruments, net earnings and cash flow from operations is included in “
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we periodically enter into financial hedging activities with respect to a portion of our production through various financial transactions that hedge future prices received. The key terms to all our oil, gas and NGL derivative financial instruments as of December 31, 2013 are presented in Note 2 to the financial statements under “
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Consolidated Comprehensive Statements of Earnings
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Consolidated Statements of Stockholders’ Equity
Notes to Consolidated Financial Statements
All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2013 and 2012, and the related consolidated comprehensive statements of earnings, cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2013. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Devon Energy Corporation’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report contained in “Item 9A. Controls and Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with United States generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ KPMG LLP
Oklahoma City, Oklahoma
February 28, 2014
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Devon Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities in many of its producing areas, making it one of North America’s larger processors of natural gas.
Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the United States of America and reflect industry practices. The more significant of such policies are discussed below.
Principles of Consolidation
The accounts of Devon and its wholly owned and controlled subsidiaries are included in the accompanying financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
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proved reserves and related present value of future net revenues;
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the carrying value of oil and gas properties;
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derivative financial instruments;
•
the fair value of reporting units and related assessment of goodwill for impairment;
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income taxes;
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asset retirement obligations;
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obligations related to employee pension and postretirement benefits; and
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legal and environmental risks and exposures.
Revenue Recognition and Gas Balancing
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying comprehensive statements of earnings.
Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is measured based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells’ reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
During 2013, 2012 and 2011, no purchaser accounted for more than 10 percent of Devon’s operating revenues from continuing operations.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon’s derivative financial instruments typically include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2013, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings.
By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. As of December 31, 2013, Devon held $3 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying balance sheet.
General and Administrative Expenses
General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Share Based Compensation
Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s consolidation of its U.S. operations announced in October 2012, certain share based awards were accelerated and recognized as a component of restructuring costs in the accompanying comprehensive statements of earnings.
Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share based awards. However, Devon has historically cancelled these shares upon repurchase.
Income Taxes
Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.
Net Earnings (Loss) Per Common Share
Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
Investments
Devon periodically invests excess cash in United States and Canadian treasury securities and other marketable securities. Devon considers securities with original contractual maturities in excess of three months, but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.
Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. Such debt securities totaled $62 million and $64 million at December 31, 2013 and 2012, respectively, and are included in other long-term assets in the accompanying balance sheet. Devon has the ability to hold the securities until maturity.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to four years.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.
Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. The estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties.
Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2013, qualified for hedge accounting treatment.
Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Devon performed annual impairment tests of goodwill in the fourth quarters of 2013, 2012 and 2011. Based on these assessments, no impairment of goodwill was required.
The table below provides a summary of Devon’s goodwill, by assigned reporting unit. The decrease in Devon’s goodwill from 2012 to 2013 was primarily due to changes in the exchange rate between the United States dollar and the Canadian dollar.
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.
Fair Value Measurements
Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:
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Level 1 - Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
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Level 2 - Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.
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Level 3 - Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.
Discontinued Operations
All amounts related to Devon’s International operations that were sold in 2012 and 2011 are classified as discontinued operations.
Foreign Currency Translation Adjustments
The United States dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to United States dollars using the applicable exchange rate as of the end of a reporting
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity.
2. Derivative Financial Instruments
Commodity Derivatives
As of December 31, 2013, Devon had the following open oil derivative positions. Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.
As of December 31, 2013, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the AECO index.
As of December 31, 2013, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas Index.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Foreign Currency Derivatives
As of December 31, 2013, Devon had the following open foreign currency derivative position:
Financial Statement Presentation
The following table presents the net gains and losses recognized in the accompanying comprehensive statements of earnings associated with derivative financial instruments. Net gains and losses associated with Devon’s commodity derivatives are presented in oil, gas and NGL derivatives in the accompanying comprehensive statements of earnings. Net gains and losses associated with Devon’s interest rate and foreign currency derivatives are presented in other nonoperating items in the accompanying comprehensive statements of earnings.
The following table presents the derivative fair values included in the accompanying balance sheets.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
3. Share-Based Compensation
On June 3, 2009, Devon’s stockholders adopted the 2009 Long-Term Incentive Plan, which expires on June 2, 2019. This plan authorizes the Compensation Committee, which consists of independent non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, performance restricted stock awards, Canadian restricted stock units, performance share units, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant of nonqualified stock options, restricted stock awards, restricted stock units and stock appreciation rights to directors.
In the second quarter of 2012, Devon’s stockholders adopted an amendment to the 2009 Long-Term Incentive Plan, which also expires June 2, 2019. This amendment increases the number of shares authorized for issuance from 21.5 million shares to 47.0 million shares. To calculate shares issued under the 2009 Long-Term Incentive Plan subsequent to this amendment, options and stock appreciation rights represent one share and other awards represent 2.38 shares.
Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.
Devon did not have an annual long-term incentive grant in 2013 due to revisions in the timing of the employee compensation cycle. The annual long-term incentive grant related to 2013 performance was granted in February 2014. The following table presents the effects of share-based compensation included in Devon’s accompanying comprehensive statements of earnings. The vesting for certain share-based awards was accelerated as part of Devon’s consolidation of its U.S. operations announced in October 2012. The associated expense for these accelerated awards is included in restructuring costs in the accompanying comprehensive statements of earnings. See Note 6 for further details.
Stock Options
In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zero to four years.
The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon’s common stock is based on the historical volatility of the market price of Devon’s common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon’s historical and current yield in effect at the date
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
of grant. The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term of the option at the date of grant. The expected term of the options is based on historical exercise and termination experience for various groups of employees and directors. Each group is determined based on the similarity of their historical exercise and termination behavior. The following table presents a summary of the grant-date fair values of stock options granted and the related assumptions for 2012 and 2011. All such amounts represent the weighted-average amounts for each year. No stock options were granted in 2013.
The following table presents a summary of Devon’s outstanding stock options.
The aggregate intrinsic value of stock options that were exercised during 2013, 2012 and 2011 was $0.3 million, $34 million and $81 million, respectively. As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested stock options was $19 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Restricted Stock Awards and Units
Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from zero to four years. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period. The following table presents a summary of Devon’s unvested restricted stock awards and units.
The aggregate fair value of restricted stock awards and units that vested during 2013, 2012 and 2011 was $141 million, $112 million and $145 million, respectively. As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested restricted stock awards and units was $166 million. Such cost is expected to be recognized over a weighted-average period of 2.2 years.
Performance Based Restricted Stock Awards
Performance based restricted stock awards are granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zero to four years. If Devon meets or exceeds the performance target, the awards vest after the recipient meets the related requisite service period. If the performance target and service period requirement are not met, the award does not vest. Once vested, recipients are entitled to dividends on the awards. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of Devon’s performance based restricted stock awards.
As of December 31, 2013, Devon’s unrecognized compensation cost related to these awards was $3 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Performance Share Units
Performance share units are granted to certain members of Devon’s senior management. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s total shareholder return (“TSR”) to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200 percent of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.
At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents a summary of the grant-date fair values of performance share units granted and the related assumptions.
The following table presents a summary of Devon’s performance share units.
(1) A maximum of 1.9 million common shares could be awarded based upon Devon’s final TSR ranking.
As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested units was $24 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
4. Asset impairments
In 2013 and 2012, Devon recognized asset impairments related to its oil and gas property and equipment and its U.S. midstream assets as presented below.
Oil and Gas Impairments
Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1.
The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which reduced proved reserve values.
Midstream Impairments
Due to declining natural gas production resulting from low natural gas and NGL prices, Devon determined that the carrying amounts of certain of its midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models. The fair value of Devon’s midstream assets is considered a Level 3 fair value measurement.
5. Other Operating Items
During 2011, Devon received $88 million of excess insurance recoveries related to certain weather and operational claims.
6. Restructuring Costs
Office Consolidation
In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon closed its office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Divestiture of Offshore Assets
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of December 31, 2012, Devon had divested all of its U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.
Financial Statement Presentation
The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings.
Employee severance and retention - As of December 31, 2013, Devon had incurred $90 million of employee severance and retention costs associated with the office consolidation. This included amounts related to cash severance costs and accelerated vesting of share-based grants.
Lease obligations and other - As of December 31, 2013, Devon had incurred $28 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that it ceased using as a part of the office consolidation. Devon’s estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that it may receive over the term of the leases, as well as the amount of variable operating costs that it will be required to pay under the leases.
The schedule below summarizes Devon’s restructuring liabilities.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
7. Income Taxes
Income Tax Expense (Benefit)
Devon’s income tax components are presented in the following table.
Total income tax expense (benefit) differed from the amounts computed by applying the United States federal income tax rate to earnings from continuing operations before income taxes as a result of the following:
Pursuant to the completed and planned divestitures of Devon’s International assets located outside North America, a portion of Devon’s foreign earnings had been deemed to no longer be indefinitely reinvested. As of December 31, 2012, Devon had recognized a $936 million deferred income tax liability related to assumed repatriations of earnings from its foreign subsidiaries, including $725 million of deferred income tax expense recognized in 2011.
In the second and fourth quarters of 2013, Devon repatriated to the U. S. a total of $4.3 billion of its cash held outside of the U. S. In the fourth quarter of 2013, Devon announced plans to divest of its Canadian conventional assets. These events resulted in an incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Deferred Tax Assets and Liabilities
The tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities are presented below:
Devon has recognized a $248 million deferred tax asset related to foreign tax credit carryforwards which expire between 2019 and 2023. Devon expects the tax benefits from the foreign tax credits to be utilized between 2014 and 2016. Devon also has recognized $183 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The carryforwards consist of $673 million of Canadian net operating loss carryforwards, which expire between 2028 and 2033, and $197 million of state net operating loss carryforwards, which expire primarily between 2014 and 2032. Devon expects the tax benefits from the Canadian net operating loss carryforwards to be utilized between 2014 and 2017 and the state net operating loss carryforwards to be utilized between 2014 and 2020. Devon has also recognized a $105 million deferred tax asset related to alternative minimum tax credits which have no expiration date and will be available for use against tax on future taxable income.
The expected utilization of Devon’s carryforwards and credits is based upon current estimates of taxable income, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil, gas and NGL prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon’s future taxable income will more likely than not be sufficient to utilize its tax carryforwards and credits prior to their expiration.
As of December 31, 2013, Devon’s unremitted foreign earnings totaled approximately $4.3 billion. Of this amount, approximately $1.5 billion was deemed to be indefinitely reinvested into the development and growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for United States
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income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to United States income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
Devon has deemed the remaining $2.8 billion of unremitted earnings not to be indefinitely reinvested. Consequently, Devon has recognized a $157 million deferred tax liability associated with such unremitted earnings as of December 31, 2013.
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits.
Devon’s unrecognized tax benefit balance at December 31, 2013 and 2012, included $32 million and $27 million, respectively, of interest and penalties. If recognized, $198 million of Devon’s unrecognized tax benefits as of December 31, 2013 would affect Devon’s effective income tax rate. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.
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8. Earnings Per Share
The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings per share.
Certain options to purchase shares of Devon’s common stock were excluded from the dilution calculations because the options were antidilutive. These excluded options totaled 7 million, 9 million and 3 million in 2013, 2012 and 2011, respectively.
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9. Other Comprehensive Earnings
Components of other comprehensive earnings consist of the following:
(1) These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of general and administrative expenses on the accompanying comprehensive statements of earnings (see “Retirement Plans” note for additional details).
10. Supplemental Information to Statements of Cash Flows
11. Short-Term Investments
The components of short-term investments include the following:
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12. Accounts Receivable
The components of accounts receivable include the following:
13. Acquisitions and Divestitures
Crosstex Merger
On October 21, 2013, Devon, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) announced plans to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), a master limited partnership and a general partner entity, which will both be publicly traded entities.
In exchange for a controlling interest in both EnLink and the Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink will each own 50% of EnLink Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval. Devon expects Crosstex Energy, Inc. shareholders will approve the transaction, allowing Devon and Crosstex to complete the transaction near the end of the first quarter of 2014.
Upon closing of the transactions, the pro forma ownership of EnLink will be approximately:
•
70% - Devon Energy Corporation
•
30% - Current Crosstex Energy, Inc. public stockholders
Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:
•
53% - Devon Energy Corporation
•
40% - Current Crosstex Energy, L.P. public unitholders
•
7% - the General Partner
GeoSouthern Acquisition
On November 20, 2013, Devon entered into an agreement with GeoSouthern Intermediate Holdings, LLC, to acquire certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford Shale in south Texas for $6 billion in cash. The transaction is expected to close in the first quarter of 2014.
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Subsequent Event (unaudited)
In conjunction with the announcement of the GeoSouthern acquisition, Devon also announced plans to divest certain non-core properties located throughout Canada and the U.S. On February 19, 2014, Devon announced its first transaction as part of this divestiture program, in which it agreed to sell the majority of its Canadian conventional assets to Canadian Natural Resources Limited for approximately $2.8 billion ($3.125 billion in Canadian dollars). This transaction is expected to close early in the second quarter of 2014.
14. Debt and Related Expenses
A summary of Devon’s debt is as follows:
(1) 2013 short-term debt consists of $2.25 billion of senior notes recently issued in conjunction with the planned GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014.
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Debt maturities as of December 31, 2013, excluding premiums and discounts, are as follows (in millions):
Credit Lines
Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that matures on October 24, 2018. However, prior to the maturity date, Devon has the option to extend the maturity for up to one additional one-year period, subject to the approval of the lenders.
Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $3.8 million that is payable quarterly in arrears. As of December 31, 2013, there were no borrowings under the Senior Credit Facility.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying financial statements. Also, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of December 31, 2013, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 25.7 percent.
Commercial Paper
Devon has access to $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2013, Devon’s weighted average borrowing rate on its commercial paper borrowings was 0.30 percent.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2013, as listed in the table presented at the beginning of this note.
GeoSouthern Debt
In December 2013, in conjunction with the planned GeoSouthern acquisition, Devon issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes resulting in cash proceeds of approximately
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$2.2 billion, net of discounts and issuance costs. The floating rate senior notes due in 2015 bear interest at a rate equal to three-month LIBOR plus 0.45 percent, which rate will be reset quarterly. The floating rate senior notes due in 2016 bears interest at a rate equal to three-month LIBOR plus 0.54 percent, which rate will be reset quarterly. The schedule below summarizes the key terms of these notes ($ in millions).
In the event that GeoSouthern acquisition is not completed on or prior to June 30, 2014, Devon is required to redeem each series of new senior notes at 101% of the aggregate principal amount of such series, plus accrued and unpaid interest. Due to the redemption features, these senior notes were classified as short-term debt on Devon’s consolidated balance sheet as of December 31, 2013 and will be reclassified as long-term debt once the acquisition is completed.
Additionally, during December 2013, Devon entered into a term loan agreement with a group of major financial institutions pursuant to which Devon may draw up to $2.0 billion to finance, in part, the GeoSouthern acquisition and to pay transaction costs. Half of any loans under the term loan agreement will have a maturity of three years and the other half will have a maturity of five years (the “5-Year Loans”). The 5-Year Loans will provide for the partial amortization of principal during the last two years that they are outstanding. Loans borrowed under the term loan agreement may, at the election of Devon, bear interest at various fixed rate options for periods up to six months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. There were no borrowings under the term loan agreement as of December 31, 2013.
Other Notes
In 2012, 2011, 2009 and 2002 Devon issued senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper and credit facility borrowings. The schedule below summarizes the key terms of these notes ($ in millions).
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Ocean Debt
On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2013, including the fair value of the debt at April 25, 2003, and the effective interest rate of the debt after determining the fair values using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.
7.875% Debentures due September 30, 2031
In October 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), a wholly owned finance subsidiary, sold debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed on an unsecured and unsubordinated basis the obligations of Devon Financing under the debt securities. The proceeds were used to fund a portion of the acquisition of Anderson Exploration.
Net financing costs
The following schedule includes the components of net financing costs.
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15. Asset Retirement Obligations
The schedule below summarizes changes in Devon’s asset retirement obligations.
During 2012, Devon recognized revisions to its asset retirement obligations totaling $420 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.
16. Retirement Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans. The qualified plans provide retirement benefits for certain U.S. and Canadian employees meeting certain age and service requirements. Benefits for the qualified plans are based on the employees’ years of service and compensation and are funded from assets held in the plans’ trusts.
The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans’ benefits are based on the employees’ years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans’ benefit obligations. The total value of these trusts was $27 million and $31 million at December 31, 2013 and 2012, respectively, and is included in other long-term assets in the accompanying balance sheets. For the remaining nonqualified plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.
Devon also has defined benefit postretirement plans that provide benefits for substantially all U.S. employees. The plans provide medical and, in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.
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Benefit Obligations and Funded Status
The following table presents the funded status of Devon’s qualified and nonqualified pension and postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans was $1.1 billion and $1.2 billion at December 31, 2013 and 2012, respectively. Devon’s benefit obligations and plan assets are measured each year as of December 31. Devon’s 2012 plan settlements relate to a plan amendment which removed a dollar cap on lump sum payments and revised optional forms of payment to include a lump sum distribution feature. The projected benefit obligation for Devon’s qualified plans was fully funded as of December 31, 2013 and 2012.
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The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $11 million and $10 million for 2013 and 2012, respectively, which were transferred from the trusts established for the nonqualified plans.
Certain of Devon’s pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2013 and 2012 as presented in the table below.
Net Periodic Benefit Cost and Other Comprehensive Earnings
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
(1) These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
(2) Net periodic benefit cost is a component of general and administrative expenses on the accompanying comprehensive statements of earnings.
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The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2014.
Assumptions
The following table presents the weighted average actuarial assumptions used to determine obligations and periodic costs.
Discount rate - Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.
Rate of compensation increase - For measurement of the 2013 benefit obligation for the pension plans, a 4.48 percent compensation increase was assumed.
Expected return on plan assets - The expected rate of return on plan assets was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types. See the pension plan assets section below for more information on Devon’s target allocations.
Other assumptions - For measurement of the 2013 benefit obligation for the other postretirement medical plans, a 7.9 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2014. The rate was assumed to decrease annually to an ultimate rate of 5 percent in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2013, by less than $1 million and would change the 2014 service and interest cost components of net periodic benefit cost by less than $1 million.
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Pension Plan Assets
Devon’s overall investment objective for its pension plans’ assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon’s target allocation for its pension plan assets.
The fair values of Devon’s pension assets are presented by asset class in the following tables.
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The following methods and assumptions were used to estimate the fair values in the tables above.
Fixed-income securities - Devon’s fixed-income securities consist of United States Treasury obligations, bonds issued by investment-grade companies from diverse industries, and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.
Devon’s fixed income securities also include commingled funds that primarily invest in long-term bonds and United States Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.
Equity securities - Devon’s equity securities include a commingled global equity fund that invests in large, mid and small capitalization stocks across the world’s developed and emerging markets. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.
Other securities - Devon’s other securities include commingled, short-term investment funds. These securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.
Devon’s hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategies and a hedge fund of funds that invests both long and short using a variety of investment strategies. Devon’s hedge fund of funds is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.
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Included below is a summary of the changes in Devon’s Level 3 plan assets (in millions).
Expected Cash Flows
The following table presents expected cash flow information for Devon’s pension and postretirement benefit plans.
Expected contributions included in the table above include amounts related to Devon’s qualified plans, nonqualified plans and postretirement plans. Of the benefits expected to be paid in 2014, the $12 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans and the $3 million of postretirement benefits is expected to be funded from Devon’s available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.
Defined Contribution Plans
Devon maintains several defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. The following table presents Devon’s expense related to these defined contribution plans.
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17. Stockholders’ Equity
The authorized capital stock of Devon consists of 1 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Devon’s Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”). At December 31, 2013, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share on all matters submitted to a vote of the stockholders. Devon, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of Devon’s common stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.
Stock Repurchases
In the fourth quarter of 2011, Devon completed its 2010 repurchase program. In total, Devon repurchased 49.2 million shares for $3.5 billion, or $71.18 per share.
Dividends
Devon paid common stock dividends of $348 million, $324 million and $278 million in 2013, 2012 and 2011 respectively. The quarterly cash dividend was $0.16 per share in the first quarter of 2011. Devon increased the dividend rate to $0.17 per share in the second quarter of 2011 and further increased the dividend rate to $0.20 per share in the first quarter of 2012. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013.
18. Commitments and Contingencies
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.
Royalty Matters
Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. The suits allege that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold. Devon’s largest exposure for such matters relates to royalties in New Mexico. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
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Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
Commitments
The following is a schedule by year of Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2013.
Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.
Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.
Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.
Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in general and administrative expenses under operating leases, net of sub-lease income, was $26 million, $42 million and $42 million in 2013, 2012 and 2011, respectively.
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19. Fair Value Measurements
The following tables provide carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at December 31, 2013 and December 31, 2012. Therefore, such financial assets and liabilities are not presented in the following tables. Additionally, information regarding the fair values of Devon’s midstream and pension plan assets is provided in Note 4 and Note 16, respectively.
The following methods and assumptions were used to estimate the fair values in the tables above.
Level 1 Fair Value Measurements
Cash equivalents and short-term investments - Amounts consist primarily of United States and Canadian treasury securities and money market investments. The fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents and short-term investments - Amounts consist primarily of Canadian agency and provincial securities and commercial paper investments. The fair value approximates the carrying value.
Commodity, interest rate and foreign currency derivatives - The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
Debt - Devon’s debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt and floating-rate debt are estimated based on rates available for debt with similar terms and maturity. The fair value of Devon’s commercial paper and credit facility borrowings are the carrying values.
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Level 3 Fair Value Measurements
Long-term investments - Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to auction failures and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on continued receipts of principal at par, the collection of all accrued interest to date, the probability of full repayment of the securities considering the United States government guarantees substantially all of the underlying student loans, and the AAA credit rating of the securities. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of December 31, 2013 and December 31, 2012.
Included below is a summary of the changes in Devon’s Level 3 fair value measurements.
20. Discontinued Operations
Revenues related to Devon’s discontinued operations totaled $43 million during 2011. Devon did not have revenues related to its discontinued operations during 2013 or 2012. The following table presents the earnings (loss) from Devon’s discontinued operations.
21. Segment Information
Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s segments are all primarily engaged in oil and gas producing activities, and certain information regarding such activities for each segment is included in Note 22. Segment revenues are all from external customers.
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(1) Amounts in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $153 million in 2011.
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22. Supplemental Information on Oil and Gas Operations (Unaudited)
Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon’s discontinued operations.
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities.
Costs incurred in the tables above include additions and revisions to Devon’s asset retirement obligations. The proceeds received from our joint venture transactions at closing have not been netted against the costs incurred. At December 31, 2013, our partners’ remaining commitments to fund our future costs associated with these joint venture transactions totaled approximately $1.4 billion.
Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $368 million, $359 million and
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$337 million in the years 2013, 2012 and 2011, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $42 million, $36 million and $45 million in the years 2013, 2012 and 2011, respectively.
Capitalized Costs
The following tables reflect the aggregate capitalized costs related to oil and gas activities.
The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2013.
Included in the $2.8 billion of oil and gas properties not subject to amortization are approximately $1.6 billion of costs that we deem significant for individual assessment. These costs relate to our investments in the Pike thermal oil project in Canada, the Mississippian-Woodford Trend in Oklahoma and a portion of our properties in the Permian Basin in Texas. Based on our development plans, we expect to begin including the Pike costs in the amortization computation in 2015 when we receive regulatory approval for the first phase of this project and subsequently begin recognizing the associated proved reserves. We are evaluating and developing the Mississippian-Woodford and Permian properties over the next 3 to 4 years. We expect to include the costs in the amortization computation as we complete our evaluation activities.
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Results of Operations
The following tables include revenues and expenses associated with Devon’s oil and gas producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Proved Reserves
The following tables present Devon’s estimated proved reserves by product by country.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Proved Undeveloped Reserves
The following table presents the changes in Devon’s total proved undeveloped reserves during 2013 (in MMBoe).
At December 31, 2013, Devon had 701 MMBoe of proved undeveloped reserves. This represents a 17 percent decrease as compared to 2012 and represents 24 percent of total proved reserves. Drilling and development activities increased Devon’s proved undeveloped reserves 95 MMBoe and resulted in the conversion of 147 MMBoe, or 18 percent, of the 2012 proved undeveloped reserves to proved developed reserves. Costs incurred related to the development and conversion of Devon’s proved undeveloped reserves were $1.9 billion for 2013. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 78 MMBoe primarily due to evaluations of certain U.S. onshore dry-gas areas, which Devon does not expect to develop in the next five years. The largest revisions relate to the dry-gas areas in the Cana-Woodford Shale in western Oklahoma, Carthage in east Texas and the Barnett Shale in north Texas.
A significant amount of Devon’s proved undeveloped reserves at the end of 2013 related to its Jackfish operations. At December 31, 2013 and 2012, Devon’s Jackfish proved undeveloped reserves were 441 MMBoe and 429 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2031.
Price Revisions
2013 - Reserves increased 94 MMBoe primarily due to higher gas prices. Of this increase, 43 MMBoe related to the Barnett Shale and 19 MMBoe related to the Rocky Mountain area.
2012 - Reserves decreased 171 MMBoe primarily due to lower gas prices. Of this decrease, 100 MMBoe related to the Barnett Shale and 25 MMBoe related to the Rocky Mountain area.
- Reserves decreased 21 MMBoe due to lower gas prices and higher oil prices. The higher oil prices increased Devon’s Canadian royalty burden, which reduced Devon’s oil reserves.
Revisions Other Than Price
Total revisions other than price for 2013, 2012 and 2011 primarily related to Devon’s evaluation of certain dry gas regions, with the largest revisions being made in the Cana-Woodford Shale, Barnett Shale and Carthage area.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Extensions and Discoveries
2013 - Of the 261 MMBoe of extensions and discoveries, 76 MMBoe related to the Permian Basin in west Texas and southeast New Mexico, 54 MMBoe related to the Barnett Shale, 42 MMBoe related to the Anadarko Basin, 38 MMBoe related to Jackfish in northeast Alberta, Canada and 32 MMBoe related to the Mississippian-Woodford Trend in north Oklahoma.
The 2013 extensions and discoveries included 175 MMBoe related to additions from Devon’s infill drilling activities, including 23 MMBoe at the Cana-Woodford Shale, 54 MMBoe at the Barnett Shale, 38 MMBoe at Jackfish, 33 MMBoe at the Permian Basin and 20 MMBoe at the Mississippian-Woodford Trend.
2012 - Of the 449 MMBoe of extensions and discoveries, 151 MMBoe related to the Cana-Woodford Shale, 95 MMBoe related to the Barnett Shale, 72 MMBoe related to the Permian Basin, 67 MMBoe related to Jackfish, 16 MMBoe related to the Rocky Mountain area and 18 MMBoe related to the Granite Wash area.
The 2012 extensions and discoveries included 229 MMBoe related to additions from Devon’s infill drilling activities, including 134 MMBoe at the Cana-Woodford Shale and 82 MMBoe at the Barnett Shale.
2011 - Of the 421 MMBoe of extensions and discoveries, 162 MMBoe related to the Cana-Woodford Shale, 115 MMBoe related to the Barnett Shale, 39 MMBoe related to the Permian Basin, 30 MMBoe related to Jackfish, 19 MMBoe related to the Rocky Mountain area and 17 MMBoe related to the Granite Wash area.
The 2011 extensions and discoveries included 168 MMBoe related to additions from Devon’s infill drilling activities, including 80 MMBoe at the Cana-Woodford Shale and 77 MMBoe at the Barnett Shale.
Standardized Measure
The tables below reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2013 estimates, Devon’s future realized prices were assumed to be $88.19 per barrel of oil, $47.44 per barrel of bitumen, $3.10 per Mcf of gas and $26.28 per barrel of natural gas liquids. Of the $10.8 billion of future development costs as of the end of 2013, $1.9 billion, $1.5 billion and $0.7 billion are estimated to be spent in 2014, 2015 and 2016, respectively.
Future development costs include not only development costs, but also future asset retirement costs. Included as part of the $10.8 billion of future development costs are $2.7 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:
23. Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of Devon’s unaudited interim results of operations.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Earnings (Loss) from Continuing Operations
The first quarter of 2013 includes U.S. and Canadian asset impairments totaling $1.9 billion ($1.3 billion after income taxes, or $3.25 per diluted share).
The fourth quarter of 2012 includes U.S. and Canadian asset impairments totaling $0.9 billion ($0.6 billion after income taxes, or $1.46 per diluted share).
The third quarter of 2012 includes U.S. asset impairments totaling $1.1 billion ($0.7 billion after income taxes, or $1.78 per diluted share).
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2013 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (the “1992 COSO Framework”). Based on this evaluation under the 1992 COSO Framework, which was completed on February 19, 2014, management concluded that its internal control over financial reporting was effective as of December 31, 2013.
The effectiveness of our internal control over financial reporting as of December 31, 2013 has been audited by KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as of and for the year ended December 31, 2013, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” in this report.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting during the fourth quarter of 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Not Applicable.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2014.
Item 11. Executive Compensation
The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2014.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2014.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2014.
Item 14. Principal Accounting Fees and Services
The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2014.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at “Item 8. Financial Statements and Supplementary Data” in this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated financial statements or notes thereto.
3. Exhibits
Exhibit No.
Description
1.1
Underwriting Agreement, dated December 11, 2013, by and among Registrant and Morgan Stanley & Co. LLC, Barclays Capital Inc. and Goldman, Sachs & Co., as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed December 16, 2013).
2.1
Agreement and Plan of Merger dated October 21, 2013, by and among Registrant, Devon Gas Services, L.P., Acacia Natural Gas Corp I, Inc., Crosstex Energy, Inc., New Public Rangers L.L.C., Boomer Merger Sub, Inc. and Rangers Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed October 22, 2013).
2.2
Contribution Agreement dated October 21, 2013, by and among Registrant, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc., Crosstex Energy, L.P. and Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 2.2 to Registrant’s Form 8-K filed October 22, 2013).
2.3
Purchase and Sale Agreement dated November 20, 2013, among GeoSouthern Intermediate Holdings, LLC, GeoSouthern Energy Corporation (solely with respect to certain sections specified therein), and Devon Energy Production Company, L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K/A filed February 18, 2014).
3.1
Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s 10-K for the fiscal year ending December 31, 2012).
3.2
Registrant’s Bylaws (incorporated by reference to Exhibit 3.2 of Registrant’s Form 8-K filed June 8, 2012).
3.3
Amendment No. 1 to Registrant’s Bylaws (incorporated by reference to Exhibit 3.2 to Registrant’s Form 8-K filed September 16, 2013).
4.1
Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 2.40% Senior Notes due 2016, the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011).
4.2
Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 2.40% Senior Notes due 2016, the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed July 12, 2011).
Exhibit No.
Description
4.3
Supplemental Indenture No. 2, dated as of May 14, 2012, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 1.875% Senior Notes due 2017, the 3.250% Senior Notes due 2022 and the 4.750% Senior Notes due 2042 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed May 14, 2012).
4.4
Supplemental Indenture No. 3, dated as of December 19, 2013, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the Floating Rate Senior Notes due 2015, the Floating Rate Senior Notes due 2016, the 1.200% Senior Notes due 2016 and the 2.50% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 19, 2013).
4.5
Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176).
4.6
Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176).
4.7
Supplemental Indenture No. 3, dated as of January 9, 2009, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 6.30% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed January 9, 2009; File No. 000-32318).
4.8
Indenture dated as of October 3, 2001, by and among Devon Financing Corporation, U.L.C. as Issuer, Registrant as Guarantor, and The Bank of New York Mellon Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 7.875% Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4 as filed October 31, 2001; File No. 333-68694).
4.9
Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 10.24 to the Form 10-Q for the period ended June 30, 1998 of Ocean Energy, Inc.; File No. 001-14252).
4.10
First Supplemental Indenture, dated March 30, 1999 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.5 to Ocean Energy, Inc.’s Form 10-Q for the period ended March 31, 1999; File No. 001-08094).
4.11
Second Supplemental Indenture, dated as of May 9, 2001 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 99.2 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444).
4.12
Third Supplemental Indenture, dated January 23, 2006 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.23 of Registrant’s Form 10-K for the year ended December 31, 2005; File No. 001-32318).
Exhibit No.
Description
4.13
Senior Indenture dated September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., as Trustee, and Specimen of 7.50% Senior Notes (incorporated by reference to Exhibit 4.4 to Ocean Energy Inc.’s Form 10-K for the year ended December 31, 1997; File No. 001-08094).
4.14
First Supplemental Indenture, dated as of March 30, 1999 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 4.10 to Ocean Energy’s Form 10-Q for the period ended March 31, 1999; File No. 001-08094).
4.15
Second Supplemental Indenture, dated as of May 9, 2001 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File No. 033-06444).
4.16
Third Supplemental Indenture, dated December 31, 2005 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A.., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K for the year ended December 31, 2005; File No. 001-32318).
9.1
Voting Agreement dated October 21, 2013, by and among Registrant, Blackstone/GSO Capital Solutions Overseas Master Fund L.P. and Blackstone/GSO Capital Solutions Fund LP (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed October 22, 2013).
10.1
Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, each lender from time to time party thereto, each L/C Issuer from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed October 29, 2012).
10.2
Extension Agreement dated September 3, 2013 to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender, with respect to Borrower’s extension of the Maturity Date from October 24, 2017 to October 24, 2018 (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 6, 2013).
10.3
First Amendment to Credit Agreement dated February 3, 2014, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, each lender from time to time party thereto, each L/C Issuer from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed February 7, 2014).
10.4
Credit Agreement dated as of December 16, 2013, among Devon Energy Corporation, as Borrower, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed December 20, 2013).
Exhibit No.
Description
10.5
Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Registrant’s Form S-8 Registration No.333-182198, filed June 18, 2012).*
10.6
Devon Energy Corporation 2013 Amendment (effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2013).*
10.7
Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-127630, filed August 17, 2005).*
10.8
First Amendment to Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Appendix A to Registrant’s Proxy Statement for the 2006 Annual Meeting of Stockholders filed on April 28, 2006).*
10.9
Devon Energy Corporation Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K, filed June 8, 2012)*
10.10
Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 7, 2013).*
10.11
Devon Energy Corporation Amendment No. 1, dated July 19, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*
10.12
Devon Energy Corporation Amendment No. 2, dated July 26, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*
10.13
Devon Energy Corporation Amendment No. 3, dated December 16, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*
10.14
Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K, filed February 24, 2012).*
10.15
Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K, filed February 24, 2012).*
10.16
Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K, filed February 24, 2012).*
10.17
Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K, filed February 24, 2012).*
10.18
Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K, filed February 24, 2012).*
10.19
Devon Energy Corporation Incentive Savings Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-179181, filed January 26, 2012).*
Exhibit No.
Description
10.20
Amended and Restated Form of Employment Agreement between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor dated December 15, 2008 (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009).*
10.21
Form of Amendment No. 1 to the Amended and Restated Employment Agreement, incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009, between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor dated April 19, 2011. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed April 25, 2011).*
10.22
Form of Employment Agreement between Registrant and Tony D. Vaughn dated June 10, 2013 (Amended and Restated Form of Employment Agreement dated December 15, 2008, (Exhibit 10.20 above), as amended by Amendment No. 1 thereto dated April 19, 2011, (Exhibit 10.21 above)).*
10.23
Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor for performance based restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed December 7, 2011).*
10.24
Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted stock awarded (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 21, 2013).*
10.25
Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted stock awarded.*
10.26
Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor for performance based restricted share units awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed December 7, 2011).*
10.27
Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted share units awarded (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 21, 2013).*
10.28
Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted share units awarded.*
10.29
Form of Incentive Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for incentive stock options granted (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 25, 2011).*
Exhibit No.
Description
10.30
Form of Employee Nonqualified Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for nonqualified stock options granted (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 25, 2011).*
10.31
Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for nonqualified stock options granted (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed on February 25, 2010).*
10.32
Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for restricted stock awards (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 25, 2011).*
10.33
Form of Notice of Grant of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for restricted stock awards.*
10.34
Form of Letter Agreement amending the restricted stock award agreements and nonqualified stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and J. Larry Nichols, John Richels and Darryl G. Smette (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 25, 2011).*
10.35
Amendment to Incentive Stock Option Award Agreement between Registrant and J. Larry Nichols dated December 19, 2012, amending the Incentive Stock Option Agreements under the 2009 Long-Term Incentive Plan between Registrant and J. Larry Nichols (incorporated by reference to Exhibit 10.24 to Registrant’s Form 10-K filed February 21, 2013). *
Statement of computations of ratio of earnings to fixed charges.
Registrant’s Significant Subsidiaries.
23.1
Consent of KPMG LLP.
23.2
Consent of LaRoche Petroleum Consultants, Ltd.
23.3
Consent of Deloitte.
31.1
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1
Report of LaRoche Petroleum Consultants, Ltd.
99.2
Report of Deloitte.
101.INS
XBRL Instance Document.
Exhibit No.
Description
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
* Compensatory plans or arrangements
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DEVON ENERGY CORPORATION
By: /s/ JOHN RICHELS
John Richels
President and Chief Executive Officer
February 28, 2014
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ JOHN RICHELS
President, Chief Executive Officer and
February 28, 2014
John Richels
Director
(Principal executive officer)
/s/ THOMAS L. MITCHELL
Executive Vice President
February 28, 2014
Thomas L. Mitchell
and Chief Financial Officer
(Principal financial officer and principal accounting officer)
/s/ J. LARRY NICHOLS
Executive Chairman of the Board
February 28, 2014
J. Larry Nichols
/s/ BARBARA M. BAUMANN
Director
February 28, 2014
Barbara M. Baumann
/s/ JOHN E. BETHANCOURT
Director
February 28, 2014
John E. Bethancourt
/s/ ROBERT H. HENRY
Director
February 28, 2014
Robert H. Henry
/s/ JOHN A. HILL
Director
February 28, 2014
John A. Hill
/s/ MICHAEL M. KANOVSKY
Director
February 28, 2014
Michael M. Kanovsky
/s/ ROBERT A. MOSBACHER, JR.
Director
February 28, 2014
Robert A. Mosbacher, Jr.
/s/ DUANE C. RADTKE
Director
February 28, 2014
Duane C. Radtke
/s/ MARY P. RICCIARDELLO
Director
February 28, 2014
Mary P. Ricciardello
INDEX TO EXHIBITS
Exhibit No.
Description
10.11
Devon Energy Corporation Amendment No. 1, dated July 19, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*
10.12
Devon Energy Corporation Amendment No. 2, dated July 26, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*
10.13
Devon Energy Corporation Amendment No. 3, dated December 16, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*
10.22
Form of Employment Agreement between Registrant and Tony D. Vaughn dated June 10, 2013 (Amended and Restated Form of Employment Agreement dated December 15, 2008, (Exhibit 10.20 above), as amended by Amendment No. 1 thereto dated April 19, 2011, (Exhibit 10.21 above)).*
10.25
Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted stock awarded.*
10.28
Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted share units awarded.*
10.33
Form of Notice of Grant of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for restricted stock awards.*
Statement of computations of ratio of earnings to fixed charges.
Registrant’s Significant Subsidiaries.
23.1
Consent of KPMG LLP.
23.2
Consent of LaRoche Petroleum Consultants, Ltd.
23.3
Consent of Deloitte.
31.1
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1
Report of LaRoche Petroleum Consultants, Ltd.
99.2
Report of Deloitte.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
* Compensatory plans or arrangements