UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
For the quarterly period ended March 31, 2012
or
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
(State of other jurisdiction of
incorporation or organization)
(I.R.S. Employer
identification No.)
333 West Sheridan,
Oklahoma City, Oklahoma
Registrant’s telephone number, including area code: (405) 235-3611
Former address: 20 North Broadway, Oklahoma City, Oklahoma 73102-8260
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
On April 18, 2012, 404.4 million shares of common stock were outstanding.
FORM 10-Q
TABLE OF CONTENTS
Item 1. 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
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
Signatures
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements regarding our expectations and plans, as well as future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2011 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, such as changes in the supply of and demand for oil, natural gas and NGLs and related products and services; exploration or drilling programs; political or regulatory events; general economic and financial market conditions; and other factors discussed in this report.
All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.
2
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
Revenues:
Oil, gas and NGL sales
Oil, gas and NGL derivatives
Marketing and midstream revenues
Total revenues
Expenses and other, net:
Lease operating expenses
Marketing and midstream operating costs and expenses
Depreciation, depletion and amortization
General and administrative expenses
Taxes other than income taxes
Interest expense
Restructuring costs
Other, net
Total expenses and other, net
Earnings from continuing operations before income taxes
Current income tax expense (benefit)
Deferred income tax expense
Earnings from continuing operations
Earnings (loss) from discontinued operations, net of tax
Net earnings
Basic net earnings per share:
Basic earnings from continuing operations per share
Basic earnings (loss) from discontinued operations per share
Basic net earnings per share
Diluted net earnings per share:
Diluted earnings from continuing operations per share
Diluted earnings (loss) from discontinued operations per share
Diluted net earnings per share
Comprehensive earnings:
Other comprehensive income, net of tax:
Foreign currency translation
Pension and postretirement plans
Other comprehensive earnings, net of tax
Comprehensive earnings
See accompanying notes to consolidated financial statements.
3
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Earnings from discontinued operations, net of tax
Adjustments to reconcile earnings from continuing operations to net cash from operating activities:
Unrealized change in fair value of financial instruments
Other noncash charges
Net increase in working capital
Increase in long-term other assets
Decrease in long-term other liabilities
Cash from operating activities – continuing operations
Cash from operating activities – discontinued operations
Net cash from operating activities
Cash flows from investing activities:
Capital expenditures
Purchases of short-term investments
Redemptions of short-term investments
Other
Cash from investing activities – continuing operations
Cash from investing activities – discontinued operations
Net cash from investing activities
Cash flows from financing activities:
Net commercial paper borrowings
Credit facility borrowings
Proceeds from stock option exercises
Repurchases of common stock
Dividends paid on common stock
Excess tax benefits related to share-based compensation
Net cash from financing activities
Effect of exchange rate changes on cash
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
4
CONSOLIDATED BALANCE SHEETS
ASSETS
Current assets:
Cash and cash equivalents
Short-term investments
Accounts receivable
Other current assets
Total current assets
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization
Not subject to amortization
Total oil and gas
Total property and equipment, at cost
Less accumulated depreciation, depletion and amortization
Property and equipment, net
Goodwill
Other long-term assets
Total assets
Current liabilities:
Accounts payable
Revenues and royalties payable
Short-term debt
Other current liabilities
Total current liabilities
Long-term debt
Asset retirement obligations
Other long-term liabilities
Deferred income taxes
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 404.4 million and 404.1 million shares in 2012 and 2011, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive earnings
Total stockholders’ equity
Commitments and contingencies (Note 16)
Total liabilities and stockholders’ equity
5
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Three Months Ended March 31, 2012:
Balance as of December 31, 2011
Stock option exercises
Common stock repurchased
Common stock retired
Common stock dividends
Share-based compensation
Share-based compensation tax benefits
Balance as of March 31, 2012
Three Months Ended March 31, 2011:
Balance as of December 31, 2010
Balance as of March 31, 2011
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
The accompanying unaudited financial statements and notes of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying financial statements and notes should be read in conjunction with the accompanying financial statements and notes included in Devon’s 2011 Annual Report on Form 10-K.
The accompanying unaudited interim financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary to a fair statement of Devon’s results of operations and cash flows for the three-month periods ended March 31, 2012 and 2011 and Devon’s financial position as of March 31, 2012.
2. Derivative Financial Instruments
Objectives and Strategies
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production that hedge the 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.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon’s interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount.
Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.
Devon does not hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.
Counterparty Credit Risk
By using derivative financial instruments, 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 a number of counterparties whom Devon believes are minimal 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. As of March 31, 2012, the credit ratings of all Devon’s counterparties were within established guidelines.
Commodity Derivatives
As of March 31, 2012, 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.
Period
Q2-Q4 2012
Q1-Q4 2013
Q1-Q4 2014
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As of March 31, 2012, Devon had the following open natural gas derivative positions. Devon’s natural gas derivatives settle against the Inside FERC first of the month Henry Hub index.
Interest Rate Derivatives
As of March 31, 2012, Devon had the following open interest rate derivative positions:
Notional
$ 100
750
$ 850
Foreign Exchange Derivatives
As of March 31, 2012, Devon had the following open foreign exchange rate derivative positions:
Currency
Canadian Dollar
Financial Statement Presentation
The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying comprehensive statements of earnings associated with derivative financial instruments.
Comprehensive Statement of Earnings Caption
Cash settlements:
Commodity derivatives
Interest rate derivatives
Foreign exchange derivatives
Total cash settlements
Unrealized gains (losses):
Total unrealized losses
Net gain (loss) recognized in comprehensive statements of earnings
8
The following table presents the derivative fair values included in the accompanying consolidated balance sheets.
Balance Sheet Caption
Asset derivatives:
Total asset derivatives
Liability derivatives:
Total liability derivatives
3. Restructuring Costs
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of March 31, 2012, Devon had divested all of its U.S. Offshore and International assets. Since inception of the plan, Devon had incurred $202 million of restructuring costs associated with these divestitures.
The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings. Restructuring costs related to Devon’s discontinued operations totaled $6 million in the three months ended March 31, 2011. These costs primarily related to cash severance and share-based awards and are not included in the schedule below. There were no costs related to discontinued operations in the three months ended March 31, 2012.
Lease obligations
Share-based awards
Total
The schedule below summarizes Devon’s restructuring liabilities. Devon’s restructuring liabilities for cash severance related to its discontinued operations totaled $21 million at March 31, 2011 and are not included in the schedule below.
Lease obligations settled
Cash severance settled
Lease obligations revision
9
4. Other, net
The components of other, net in the accompanying comprehensive statements of earnings include the following:
Accretion of asset retirement obligations
Interest rate swaps – unrealized fair value changes
Interest rate swaps – cash settlements
5. 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.
Attributable to participating securities
Basic earnings per share
Dilutive effect of potential common shares issuable
Diluted earnings per share
Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculations because the options are antidilutive. These excluded options totaled 6.4 million and 3.1 million during the three-month periods ended March 31, 2012 and 2011, respectively.
10
6. Other Comprehensive Earnings
Components of other comprehensive earnings consist of the following:
Foreign currency translation:
Beginning accumulated foreign currency translation
Change in cumulative translation adjustment
Income tax expense
Ending accumulated foreign currency translation
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits
Recognition of net actuarial loss and prior service cost in earnings
Ending accumulated pension and postretirement benefits
Accumulated other comprehensive earnings, net of tax
7. Supplemental Information to Statements of Cash Flows
Net change in working capital:
Decrease (increase) in accounts receivable
Increase in other current assets
(Decrease) increase in accounts payable
(Decrease) increase in revenues and royalties payable
(Decrease) increase in income taxes payable
Decrease in other current liabilities
Supplementary cash flow data – total operations:
Interest paid (net of capitalized interest)
Income taxes paid
8. Short-Term Investments
The components of short-term investments include the following:
U.S. Treasuries
Canadian Treasuries
Commercial paper
11
9. Accounts Receivable
The components of accounts receivable include the following:
Joint interest billings
Gross accounts receivable
Allowance for doubtful accounts
Net accounts receivable
10. Other current assets
The components of other current assets include the following:
Derivative financial instruments
Inventories
Income taxes receivable
Current assets held for sale
11. Goodwill
During the first three months of 2012, Devon’s Canadian goodwill increased $54 million entirely due to foreign currency translation.
12. Debt
Commercial Paper
As of March 31, 2012, Devon had $4.1 billion of outstanding commercial paper at an average rate of 0.43 percent.
Credit Lines
Devon has a $2.65 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of March 31, 2012, Devon had $750 million of borrowings under the Senior Credit Facility at an average borrowing rate of 0.47 percent. On April 7, 2012, $0.46 billion of Devon’s Senior Credit Facility matured and $150 million of borrowings were repaid on that date.
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 less than 65 percent. As of March 31, 2012, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 24.4 percent.
12
13. Asset Retirement Obligations
The schedule below summarizes changes in Devon’s asset retirement obligations.
Asset retirement obligations as of beginning of period
Liabilities incurred
Liabilities settled
Revision of estimated obligation
Accretion expense on discounted obligation
Foreign currency translation adjustment
Asset retirement obligations as of end of period
Less current portion
Asset retirement obligations, long-term
During the first quarter of 2012, Devon recognized revisions to its asset retirement obligations totaling $399 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.
14. Retirement Plans
The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.
Net periodic benefit cost:
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Net actuarial loss
Net periodic benefit cost
15. Stockholders’ Equity
Dividends
Devon paid common stock dividends of $80 million (or $0.20 per share) and $68 million (or $0.16 per share) in the first quarter of 2012 and 2011, respectively.
16. 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.
13
Royalty Matters
Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates, which resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
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.
Chief Redemption Matters
In 2006, Devon acquired Chief Holdings LLC (“Chief”) from the owners of Chief, including Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition against Rees-Jones, as the former majority owner of Chief, and Devon, as Chief’s successor pursuant to the 2006 acquisition. The petition claimed, among other things, violations of the Texas Securities Act, fraud and breaches of Rees-Jones’ fiduciary responsibility to the former owner in connection with Chief’s 2004 redemption of the owner’s minority ownership stake in Chief.
On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133 million of the judgment was also issued against Devon. Both Rees-Jones and Devon are appealing the judgment. If the appeal is unsuccessful, Devon can and will seek full payment of the judgment and any related interest, costs and expenses from Rees-Jones pursuant to an existing indemnification agreement between Rees-Jones, certain other parties and Devon. Devon does not expect to have any net exposure as a result of the judgment. However, because Devon does not have a legal right of set off with respect to the judgment, Devon has recorded in the accompanying March 31, 2012 and December 31, 2011, balance sheets both a $133 million liability relating to the judgment with an offsetting $133 million receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant to the indemnification agreement.
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.
17. 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 March 31, 2012 and December 31, 2011. Therefore, such financial assets and liabilities are not presented in the following table.
14
March 31, 2012 assets (liabilities):
Cash equivalents
Long-term investments
Debt
December 31, 2011 assets (liabilities):
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 U.S. 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 commercial paper investments. The fair value is based upon quotes from brokers, which approximate the carrying value.
Commodity, interest rate and foreign exchange derivatives — The fair values of commodity and interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward curves and quotes obtained from brokers for contracts with similar terms or quotes 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 are estimated based on rates available for debt with similar terms and maturity. The fair values of Devon’s variable-rate commercial paper and credit facility borrowings are the carrying values.
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 the AAA credit rating of the securities, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. 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 March 31, 2012 and December 31, 2011. There were no changes in the fair value of these instruments in the three month periods ended March 31, 2012 and 2011, respectively.
15
Debt — Devon’s Level 3 debt consisted of a non-interest bearing promissory note. Due to the lack of an active market, quoted marked prices for this note, or similar notes, were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt is estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125% interest rate.
Debt balance at beginning of period
Foreign exchange translation adjustment
Accretion of promissory note
Redemptions of principal
Debt balance at end of period
18. Discontinued Operations
In March 2012, Devon received $71 million upon closing the divestiture of its operations in Angola, which completed Devon’s offshore divestiture program that was announced in November 2009. In aggregate, Devon’s U.S. and International offshore divestitures have generated total proceeds of $10.1 billion, or approximately $8 billion after-tax, assuming repatriation of a substantial portion of the foreign proceeds under current U.S. tax law.
Revenues related to Devon’s discontinued operations totaled $43 million in the three months ended March 31, 2011. Devon did not have revenues related to its discontinued operations during the first three months of 2012. Earnings (loss) from discontinued operations before income taxes totaled $(16) million and $30 million in the three months ended March 31, 2012 and March 31, 2011, respectively.
The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations at December 31, 2011. Devon did not have assets or liabilities held for sale at March 31, 2012.
19. Segment Information
Devon manages its operations through distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. divisions into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian division is reported as 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. Revenues are all from external customers.
16
Total assets (1)
Capital expenditures (2)
Total continuing assets (1)
20. Subsequent Event
In April 2012, Devon closed its previously announced $2.5 billion joint venture transaction with Sinopec International Petroleum Exploration & Production Corporation. Pursuant to the agreement, Sinopec invested approximately $900 million in cash and received a 33.3% interest in five of Devon’s new ventures exploration plays in the U.S. at closing of the transaction. Additionally, Sinopec is required to fund approximately $1.6 billion of Devon’s share of future exploration, development and drilling costs associated with these plays.
17
The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month period ended March 31, 2012, compared to the three-month period ended March 31, 2011, and in our financial condition and liquidity since December 31, 2011. For information regarding our critical accounting policies and estimates, see our 2011 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Overview of 2012 Results
During the first three months of 2012 and 2011, our continuing operations generated net earnings of $414 million, or $1.03 per diluted share, and $389 million, or $0.91 per diluted share, for the respective periods. In spite of challenges from depressed natural gas prices, record production from our cornerstone development properties, including the Permian Basin, Jackfish, Cana-Woodford and the Barnett Shale, bolstered our first quarter earnings. Key measures of our financial performance are summarized below:
Total production rose by 10%, driven by oil and NGL production, which climbed 24% to 256 MBoe per day.
Gas production increased 4% to 2,628 MMcf per day.
The combined realized price without hedges for oil, gas and NGLs decreased 8% to $30.33 per Boe.
Oil, gas and NGL derivatives generated a net gain of $145 million in the first three months of 2012 and incurred a net loss of $168 million in the first three months of 2011. Included in these amounts were cash receipts of $158 million and $86 million, respectively.
Marketing and midstream operating profit decreased 7% to $112 million.
Per unit operating costs increased 9% to $8.15 per Boe.
Operating cash flow decreased 19% to $1.0 billion.
Capital spending totaled approximately $2.1 billion in the first quarter of 2012.
First-Quarter Operational Developments
We continued to aggressively ramp-up activity in the Permian Basin in the first quarter. Since year-end, we have added 5 operated rigs and now have 21 rigs running in the basin.
Permian Basin oil production increased 32 percent over the first-quarter 2011. Liquids production accounted for 76 percent of the 56,000 Boe per day produced in the Permian Basin during the first quarter.
Additionally, we recently enhanced our leasehold position in the Permian Basin by assembling a 500,000 net acre position in the Cline Shale light-oil play. We are currently drilling our first horizontal well in the Cline and expect to drill 15 wells in 2012.
Also in the Permian, we completed 16 operated Bone Spring wells in the first quarter. Initial daily production averaged 580 Boe per day per well.
Net production from our Jackfish 1 and Jackfish 2 oil sands projects in Canada averaged a record 46,000 barrels per day in the first quarter, representing a 55 percent increase over the year-ago quarter.
Construction of our third Jackfish oil sands project is now approximately 30 percent complete. Jackfish 3 is expected to produce 35,000 barrels per day before royalties for more than 20 years. Plant startup is targeted for late 2014.
Our Cana-Woodford Shale production averaged a record 271 million cubic feet of natural gas equivalent per day in the first quarter of 2012. Liquids production averaged 13,000 barrels per day, an 80 percent year-over-year increase.
Net liquids production from the Barnett Shale increased more than 20 percent compared to the year-ago quarter to 52,500 barrels per day, accounting for 23 percent of total Barnett production. In aggregate, net production reached a record 1.37 billion cubic feet of natural gas equivalent per day in the first quarter.
18
We brought seven operated Granite Wash wells online in the first quarter. Initial production from these wells averaged 1,650 Boe per day. We have an average working interest of 73 percent in these wells.
In the first quarter, we continued to capture acreage in new oil-focused opportunities. We have now contracted for or leased 250,000 net acres in an undisclosed resource play. We are targeting a position of 500,000 net acres in this new play.
Subsequent to quarter end, we closed our joint venture agreement with Sinopec. Pursuant to the agreement, Sinopec invested approximately $900 million in cash and agreed to a drilling carry worth $1.6 billion for a 33 percent interest in our 1.4 million net acres across 5 new venture plays (Mississippian, Ohio Utica, Tuscaloosa, Michigan Basin, and Rockies oil exploration).
Results of Operations
Production, Prices and Revenues
Oil (MBbls/d)
U.S.
Canada
Gas (MMcf/d)
NGLs (MBbls/d)
Combined (MBoe/d) (2)
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Combined (per Boe)
19
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales.
2011 sales
Changes due to volumes
Changes due to prices
2012 sales
Oil Sales
Oil sales increased $198 million in the first three months of 2012 due to a 26 percent increase in production. The increase was primarily due to continued development of our Jackfish thermal heavy oil projects and Permian Basin properties.
Oil sales increased $73 million in the first three months of 2012 as a result of an 8 percent increase in our realized price without hedges. The largest contributor to the increase in our realized price was the increase in the average NYMEX West Texas Intermediate index price due to broad market conditions.
Gas Sales
Gas sales decreased $306 million during the first three months of 2012 as a result of a 35 percent decrease in our realized price without hedges. This decrease was largely due to the broad deterioration of gas prices in the North American market.
Gas sales increased $41 million in the first three months of 2012 due to a 4 percent increase in production. The increased production resulted primarily from continued development activities in the liquids-rich gas portions of our Barnett and Cana-Woodford Shales. Production gains from development in these liquids-rich regions were partially offset by natural declines in our other operating areas, particularly those that produce dry gas.
NGL Sales
NGL sales increased $69 million in the first three months of 2012 due to a 21 percent increase in production. The increase in production was primarily due to increased drilling in the liquids-rich gas portions of the Barnett Shale, Cana-Woodford Shale and Granite Wash.
NGL sales decreased $20 million during the first three months of 2012 as a result of a 5 percent decrease in our realized price without hedges. The lower price was largely due to decreases in the Mont Belvieu, Texas hub price.
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 unrealized gains and losses that are 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 unrealized gains and losses.
Gas derivatives
Oil derivatives
NGL derivatives
Unrealized gains (losses) on fair value changes:
Total unrealized losses on fair value changes
20
Realized price without hedges
Cash settlements of hedges
Realized price, including cash settlements
A summary of our outstanding commodity derivatives is included in Note 2 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report. Cash settlements presented in the tables above represent realized gains or losses related to these various instruments.
In addition to cash settlements, we also recognize unrealized changes in the fair values of 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 generated a net gain of $145 million during the first three months of 2012 and incurred a net loss of $168 million during the first three months of 2011.
Marketing and Midstream Revenues and Operating Costs and Expenses
Marketing and midstream:
Revenues
Operating costs and expenses
Operating profit
Marketing and midstream operating profit decreased $10 million primarily due to lower gas and NGL prices.
Lease Operating Expenses (“LOE”)
LOE ($ in millions):
LOE per Boe:
LOE increased $0.67 per Boe during the first three months of 2012. The largest contributor to the higher unit cost is related to our liquids production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian
21
Basin in the U.S. Such projects generally require a higher cost to produce per unit than our gas projects. We also experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.
Depreciation, Depletion and Amortization (“DD&A”)
DD&A ($ in millions):
Oil & gas properties
Other properties
DD&A per Boe:
Oil and gas property DD&A increased $123 million during 2012 due to a 25 percent increase in the DD&A rate and $51 million due to our increase in production. The largest contributor to the higher rate was our drilling and development activities subsequent to the end of the first quarter of 2011.
General and Administrative Expenses (“G&A”)
Gross G&A
Capitalized G&A
Reimbursed G&A
Net G&A
Net G&A per Boe
Net G&A and net G&A per Boe increased during 2012 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 and the Cana-Woodford shale.
Taxes Other Than Income Taxes
Production
Ad valorem and other
Taxes other than income taxes % of oil, gas and NGL revenue
22
Interest Expense
Interest based on debt outstanding
Capitalized interest
Income Taxes
The following table presents our total income tax expense and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.
Total income tax expense (in millions)
U.S. statutory income tax rate
State income taxes
Taxation on Canadian operations
Effective income tax expense rate
Earnings (Loss) From Discontinued Operations
Operating earnings
Loss on sale of oil and gas properties
Earnings (loss) before income taxes
Earnings (loss) from discontinued operations
Earnings decreased in the first quarter of 2012 primarily as a result of the lost operating earnings subsequent to divesting our Brazilian assets in the second quarter of 2011 and the $16 million loss ($21 million after-tax) on the divestiture of our Angola operations.
23
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
Debt activity, net
Short-term investment activity, net
Divestitures of property and equipment
Common stock repurchases and dividends
Short-term investments at end of period
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 the first three months of 2012. Our operating cash flow decreased approximately 21 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by the effects from higher production.
In 2011, we completed our offshore divestiture program that was announced in November 2009. This program generated approximately $8 billion in after-tax proceeds, which continue to provide us with substantial liquidity to invest in our North America property base. During the first three months of 2012 and 2011, our operating cash flow funded approximately 50 percent and 70 percent, respectively, of our cash payments for capital expenditures. Leveraging our liquidity, we largely used debt to fund the remainder of our cash-based capital expenditures. This cash flow deficit was largely expected as we have allocated approximately 25% of our 2012 capital expenditure budget to exploratory projects and leasehold acquisitions that are not yet generating production revenues.
Debt Activity, Net
During the first three months of 2012, we utilized net credit facility and commercial paper borrowings of $1.1 billion to fund capital expenditures in excess of our operating cash flow. During the first three months of 2011, we utilized commercial paper borrowings of $1.2 billion to fund capital expenditures, common share repurchases and dividends in excess of our operating cash flow.
Short-term Investments
During the first three months of 2012 and 2011, we had net short-term investment redemptions totaling $0.2 billion and net purchases totaling $1.5 billion, respectively. The 2011 purchases and remaining balances as of March 31, 2012 represent our investment of a portion of the International offshore divestiture proceeds into U.S. and Canadian Treasury securities, commercial paper and other marketable securities.
During the first three months of 2012, we received $71 million from the divestiture of our Angola operations.
24
Capital Expenditures
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.
Midstream
Total continuing operations
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 $1.8 billion and $1.6 billion in the first three months of 2012 and 2011, respectively. The 13% growth in exploration and development capital spending in the first three months of 2012 was primarily due to increased new ventures exploratory activity and leasehold acquisition.
Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil transportation facilities. Our midstream capital expenditures are largely impacted by oil and gas drilling activities.
Common Stock Repurchases and Dividends
In connection with our offshore divestitures noted above, we conducted a $3.5 billion share repurchase program, which we completed in the fourth quarter of 2011. In the first quarter of 2012, we increased our dividend 25% over the first quarter of 2011 to $0.20 per share.
The following table summarizes our repurchases and our common stock dividends (amounts and shares in millions) during the first three months of 2012 and 2011.
Repurchases
Liquidity
Historically, our primary sources of capital and liquidity have been our operating cash flow 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. The following sections discuss changes to our liquidity subsequent to filing our 2011 Annual Report on Form 10-K.
Operating Cash Flow
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. We expect operating cash flow to continue to be our primary source of liquidity. To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum and maximum prices on our 2012 production. The key terms to our oil, gas and NGL derivative financial instruments as of March 31, 2012 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
25
Credit Availability
As of April 18, 2012, we had $1.5 billion of available capacity under our syndicated, unsecured Senior Credit Facility and $3.9 billion of commercial paper borrowings 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. As of March 31, 2012, we were in compliance with this covenant with a debt-to-capitalization ratio of 24.4 percent.
Although we ended the first quarter of 2012 with approximately $7.1 billion of cash and short-term investments, the vast majority of this amount consists of proceeds from our International offshore divestitures that are held by certain of our foreign subsidiaries. We do not currently expect to repatriate such amounts to the U.S. If we were to repatriate a portion or all of the cash and short-term investments held by these foreign subsidiaries, we would be required to accrue and pay current income taxes in accordance with current U.S. tax law. With these proceeds remaining outside of the U.S., we expect to continue using commercial paper and credit facility borrowings in the U.S. to supplement our U.S. operating cash flow. We do not expect near-term increases in such borrowings will have a material effect on our overall liquidity or financial condition.
We previously disclosed that we expected our 2012 capital expenditures to range from $6.2 billion to $6.8 billion. In the first quarter of 2012, we expanded our new ventures exploration activities, targeting oil and liquids-rich opportunities. As a result, we increased our total estimated 2012 capital expenditures by $1.0 billion.
In April 2012, we closed our previously announced $2.5 billion joint venture transaction with Sinopec. Pursuant to the agreement, Sinopec invested approximately $900 million in cash and received a 33.3% interest in five of our new ventures exploration plays in the U.S. at closing of the transaction. Additionally, Sinopec is required to fund approximately $1.6 billion of our share of future exploration, development and drilling costs associated with these plays.
Commodity Price Risk
We have commodity derivatives that pertain to production for the last nine months of 2012, as well as 2013 and 2014. The key terms to all our oil, gas and NGL derivative financial instruments as of March 31, 2012 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At March 31, 2012, a 10 percent increase and 10 percent decrease in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:
Gain/(loss):
Interest Rate Risk
At March 31, 2012, we had debt outstanding of $10.8 billion. Of this amount, $6.0 billion bears fixed interest rates averaging 6.3 percent. Additionally, we had $4.1 billion of outstanding commercial paper and $750 million of credit facility borrowings, bearing interest at floating rates which averaged 0.43 percent and 0.47 percent, respectively.
As of March 31, 2012, we had open interest rate swap positions that are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the Federal Funds rate. A 10 percent change in these forward curves would not materially impact our balance sheet at March 31, 2012.
26
Foreign Currency Risk
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period. A 10 percent unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our March 31, 2012 balance sheet.
Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, one of these foreign subsidiaries holds Canadian-dollar cash and engages in short-term intercompany loans with Canadian subsidiaries that are sometimes based in Canadian dollars. Additionally, at March 31, 2012, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash. The value of the intercompany loans increases or decreases from the remeasurement of the loans into the U.S. dollar functional currency. Based on the amount of the intercompany loans as of March 31, 2012, a 10 percent change in the foreign currency exchange rates would not materially impact our balance sheet.
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, Devon’s principal executive and principal financial officers have concluded that Devon’s 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 March 31, 2012, 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.
Changes in Internal Control Over Financial Reporting
There was no change in Devon’s internal control over financial reporting during the first quarter of 2012 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.
27
PART II. Other Information
There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 2011 Annual Report on Form 10-K.
There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2011 Annual Report on Form 10-K.
The following table provides information regarding purchases of our common stock that were made by us during the first quarter of 2012.
January 1 – January 31
February 1 – February 29
March 1 – March 31
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, Sun Life Assurance Company of Canada. Eligible Canadian employees purchased approximately 2,100 shares of our common stock in the first quarter of 2012, 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.
None.
28
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
ExhibitNumber
Description
29
SIGNATURES
Pursuant to the requirements 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.
30
INDEX TO EXHIBITS
31