UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
-----
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31,June 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
-----
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 000-30176
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
DELAWARE 73-1567067
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification Number)
20 NORTH BROADWAY
OKLAHOMA CITY, OKLAHOMA 73102 -826073102-8260
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (405) 235-3611
Not applicable
- --------------------------------------------------------------------------------
Former(Former name, former address and former fiscal year, if changed from
last report.report)
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]X No [ ]..
--- ---
The number of shares outstanding of Registrant's common stock, par
value $.10, as of April 30,July 31, 2002, was 156,338,000.160,200,000.
1 of 48441 total pages
(Exhibit Index is found at page 54)
DEVON ENERGY CORPORATION
Index to Form 10-Q Quarterly Report
to the Securities and Exchange Commission
Page No.
Part I. Financial Information
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets, March 31, 2002 (Unaudited) 4
and December 31, 2001
Consolidated Statements of Operations (Unaudited), 5
For the Three Months Ended March 31, 2002 and 2001
Consolidated Statements of Comprehensive Earnings 6
(Unaudited), For the Three Months Ended March 31,
2002 and 2001
Consolidated Statements of Cash Flows (Unaudited), 7
For the Three Months Ended March 31, 2002 and 2001
Notes to Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial 21Page No.
--------
Part I. Financial Information
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets, June 30, 2002 (Unaudited) 4
and December 31, 2001
Consolidated Statements of Operations (Unaudited) 5
for the Three Months and Six Months Ended June 30, 2002
and 2001
Consolidated Statements of Comprehensive Operations 7
(Unaudited) for the Three Months and Six Months Ended
June 30, 2002 and 2001
Consolidated Statements of Cash Flows (Unaudited) 8
for the Six Months Ended June 30, 2002 and 2001
Notes to Consolidated Financial Statements 9
Item 2. Management's Discussion and Analysis of Financial 27
Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market
Risk 45
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 47
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders 51
Item 6. Exhibits and Reports on Form 8-K 52
DEFINITIONS
As used in this document:
"Mcf" means thousand cubic feet
"Bcf" means billion cubic feet
"Bbl" means barrel
"MBbls" means thousand barrels
"MMBbls" means million barrels
"Boe" means equivalent barrels of oil
"Mboe" means thousand equivalent barrels of oil
"MMBoe" means million equivalent barrels of oil
"Oil" includes crude oil and condensate
"NGLs" means natural gas liquids
"C$" means Canadian dollar
2
DEVON ENERGY CORPORATION
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31,JUNE 30, 2002 AND 2001
(FORMING A PART OF FORM 10-Q QUARTERLY REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION)
3
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE DATA)
MARCH 31,JUNE 30, DECEMBER 31,
2002 2001
------------ ------------
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents $ 367 193425 185
Accounts receivable 680 537636 503
Inventories 53 4143 26
Fair value of financial instruments --9 195
Deferred income taxes 237 --
Income taxes receivable -- 68
Investments and other current assets 47 4741 45
------------ ------------
Total current assets 1,170 1,0811,161 1,022
------------ ------------
Property and equipment, at cost, based on the full cost method of
accounting for oil and gas properties ($2,6262,563 and $1,939$1,938 excluded
from amortization in 2002 and 2001, respectively) 19,140 15,59818,805 15,243
Less accumulated depreciation, depletion and amortization 6,877 6,5707,718 6,360
------------ ------------
12,263 9,02811,087 8,883
Investment in ChevronTexaco Corporation common stock, at fair value 640628 636
Fair value of financial instruments -- 31
Goodwill 3,5753,670 2,206
Assets of discontinued operations -- 212
Other assets 329 202327 194
------------ ------------
Total assets $ 17,97716,873 13,184
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade 544 465426 440
Revenues and royalties due to others 232256 170
Income taxes payable 9 3079 17
Accrued interest payable 4151 102
Merger related expenses payable 2425 7
Fair value of financial instruments 3524 15
Deferred income taxes -- 57
Accrued expenses and other current liabilities 176 73198 72
------------ ------------
Total current liabilities 1,061 9191,059 880
------------ ------------
Other liabilities 292 179289 172
Debentures exchangeable into shares of ChevronTexaco Corporation
common stock 652655 649
Other long-term debt 8,2367,377 5,940
Deferred revenue 3317 51
Fair value of financial instruments 6947 45
Liabilities of discontinued operations -- 77
Deferred income taxes 2,943 2,1422,645 2,111
Stockholders' equity:
Preferred stock of $1.00 par value ($100 liquidation value)
Authorized 4,500,000 shares; issued 1,500,000 in 2002 and 2001 1 1
Common stock of $.10 par value
Authorized 400,000,000 shares; issued 159,928,000160,200,000 in 2002 and
129,886,000 in 2001 16 13
Additional paid-in capital 5,1565,165 3,610
Accumulated deficit (95)(210) (147)
Accumulated other comprehensive loss (197)income (loss) 2 (28)
Treasury stock, at cost: 3,754,000 shares in 2002 and 2001 (190) (190)
------------ ------------
Total stockholders' equity 4,6914,784 3,259
------------ ------------
Total liabilities and stockholders' equity $ 17,97716,873 13,184
============ ============
See accompanying notes to consolidated financial statementsstatements.
4
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
THREE MONTHS ENDED MARCH 31,
---------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
2002 2001 ------------ ------------2002 2001
-------- -------- -------- --------
(UNAUDITED)
REVENUES
Oil sales $ 254 254262 209 495 427
Gas sales 468 725564 443 1,032 1,168
Natural gas liquids sales 5672 32 127 64
Marketing and midstream revenue 160 20
------------ ------------267 15 427 35
-------- -------- -------- --------
Total revenues 938 1,031
------------ ------------1,165 699 2,081 1,694
-------- -------- -------- --------
PRODUCTION AND OPERATING COSTS AND EXPENSES
Lease operating expenses 170 123166 107 325 218
Transportation costs 38 1719 76 36
Production taxes 22 4535 29 57 74
Marketing and midstream costs and expenses 125 16222 12 347 28
Depreciation, depletion and amortization of property and equipment 320 183327 180 643 357
Amortization of goodwill -- 89 -- 17
General and administrative expenses 54 26 104 49
22
------------ ------------Reduction of carrying value of oil and gas properties 651 77 651 77
-------- -------- -------- --------
Total production and operating costs and expenses 724 414
------------ ------------1,493 459 2,203 856
-------- -------- -------- --------
Earnings (loss) from operations 214 617(328) 240 (122) 838
OTHER INCOME (EXPENSES)
Interest expense (124) (34)(148) (35) (272) (69)
Effects of changes in foreign currency exchange rates (4)16 -- 12 --
Change in fair value of financial instruments (17) (14)24 7 7 (7)
Other income 15 8
------------ ------------6 12 21 20
-------- -------- -------- --------
Net other expenses (130) (40)
------------ ------------(102) (16) (232) (56)
-------- -------- -------- --------
Earnings (loss) from continuing operations before income tax expense
and cumulative effect of change in accounting principle 84 577(430) 224 (354) 782
INCOME TAX EXPENSE (BENEFIT)
Current 1 14477 (3) 87 141
Deferred 21 82
------------ ------------(304) 100 (295) 174
-------- -------- -------- --------
Total income tax expense 22 226
------------ ------------(benefit) (227) 97 (208) 315
-------- -------- -------- --------
Earnings (loss) from continuing operations before cumulative effect
of change in accounting principle 62 351(203) 127 (146) 467
DISCONTINUED OPERATIONS
Results of discontinued operations before income taxes (including
gain on disposal of $97 million in the 2002 periods) 100 16 108 35
Total income tax expense 1 7 4 15
-------- -------- -------- --------
Net results of discontinued operations 99 9 104 20
-------- -------- -------- --------
Earnings (loss) before cumulative effect of change in accounting principle (104) 136 (42) 487
Cumulative effect of change in accounting principle, net of income tax
expense of $32 million -- -- -- 49
------------ -------------------- -------- -------- --------
Net earnings 62 400(loss) (104) 136 (42) 536
Preferred stock dividends 2 2
------------ ------------3 3 5 5
-------- -------- -------- --------
Net earnings (loss) applicable to common shareholdersstockholders $ 60 398
============ ============
Net earnings before cumulative effect of change in accounting principle per
average common share outstanding:
Basic $ 0.41 2.70
============ ============
Diluted $ 0.40 2.59
============ ============
Net earnings per average common share outstanding:
Basic $ 0.41 3.08
============ ============
Diluted $ 0.40 2.96
============ ============
Weighted average common shares outstanding - basic 148 129
============ ============
Weighted average common shares outstanding - diluted 150 135
============ ============(107) 133 (47) 531
======== ======== ======== ========
See accompanying notes to consolidated financial statements.
5
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGSOPERATIONS
(IN MILLIONS)MILLIONS, EXCEPT PER SHARE AMOUNTS)
(CONTINUED)
THREE MONTHS ENDED MARCH 31,
---------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
2002 2001 ------------ ------------2002 2001
-------- -------- -------- --------
(UNAUDITED)
Net
Basic earnings (loss) per average common share outstanding:
Earnings (loss) from continuing operations $ 62 400
Other comprehensive earnings (loss), net of tax:
Foreign currency translation adjustments (2) (19)(1.31) 0.96 (0.99) 3.58
Earnings from discontinued operations 0.63 0.07 0.68 0.15
Cumulative effect of change in accounting principle -- (37)
Reclassification adjustment for derivative losses (gains)
reclassified into oil and gas sales (42) 5
Change in fair value of outstanding hedging positions (128) 13
Unrealized gains on marketable securities 3 15
------------ ------------
Comprehensive-- -- 0.38
-------- -------- -------- --------
Net earnings (loss) $ (107) 377
============ ============(0.68) 1.03 (0.31) 4.11
======== ======== ======== ========
Diluted earnings (loss) per average common share outstanding:
Earnings (loss) from continuing operations $ (1.31) 0.94 (0.99) 3.44
Earnings from discontinued operations 0.63 0.07 0.68 0.15
Cumulative effect of change in accounting principle -- -- -- 0.37
-------- -------- -------- --------
Net earnings (loss) $ (0.68) 1.01 (0.31) 3.96
======== ======== ======== ========
Weighted average common shares outstanding-basic 157 129 153 129
======== ======== ======== ========
Weighted average common shares outstanding-diluted 163 135 159 135
======== ======== ======== ========
See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWSCOMPREHENSIVE OPERATIONS
(IN MILLIONS)
THREE MONTHS ENDED MARCH 31,
---------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
2002 2001 ------------ ------------2002 2001
-------- -------- -------- --------
(UNAUDITED)
Net earnings (loss) $ (104) 136 (42) 536
Other comprehensive earnings (loss), net of tax:
Foreign currency translation adjustments 202 16 200 (3)
Cumulative effect of change in accounting principle -- -- -- (37)
Adjustment to reclassify derivative (gains) losses into
oil and gas sales 1 10 (41) 15
Change in fair value of outstanding hedging positions 4 28 (124) 41
Unrealized gains (losses) on marketable securities (8) 12 (5) 27
-------- -------- -------- --------
Comprehensive earnings (loss) $ 95 202 (12) 579
======== ======== ======== ========
See accompanying notes to consolidated financial statements.
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
SIX MONTHS ENDED JUNE 30,
--------------------------
2002 2001
---------- ----------
(UNAUDITED)
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings (loss) from continuing operations $ 62 400(146) 467
Adjustments to reconcile net earnings from continuing operations to
net cash provided by operating activities:
Depreciation, depletion and amortization of property and equipment 320 183643 357
Amortization of goodwill -- 8
Accretion17
Reduction of discounts on long-term debt, net 8 6carrying value of oil and gas properties 651 77
Effects of changes in foreign currency exchange rates 4(12) --
Change in fair value of financialderivative instruments 17 14
Cumulative effect of change in accounting principle -- (49)(7) 7
Deferred income tax expense 21 82(benefit) (295) 174
Operating cash flows of discontinued operations 20 30
Accretion of discounts on other long-term debt, net 16 11
Gain on sale of assets (2) --
Other (10) 1
Changes in assets and liabilities, net of effects of acquisitions of businesses:
Decrease (increase) in:
Accounts receivable 12 79(22) 43
Inventories 3 714 9
Prepaid expenses 5 (24)10 18
Other assets (123) (13)
Increase (decrease)(35) (15)
(Decrease) increase in:
Accounts payable 7 2(75) (17)
Income taxes payable 93 97144 (16)
Accrued expenses and other current liabilities (40) (21)40 (11)
Deferred revenue (18) (16)(33) (32)
Long-term other liabilities 1 2
------------ ------------(5) (20)
---------- ----------
Net cash provided by operating activities 372 757
------------ ------------896 1,100
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property and equipment 227 221,036 26
Capital expenditures, including business acquisitions of businesses (2,190) (346)
Decrease in other assets 2 --
------------ ------------(2,572) (998)
Discontinued operations (6) (21)
---------- ----------
Net cash used in investing activities (1,961) (324)
------------ ------------(1,542) (993)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings of long-term debt, net of issuance costs 3,742 634,730 366
Principal payments on long-term debt (1,979) (118)(3,840) (258)
Issuance of common stock, net of issuance costs 9 3218 40
Repurchase of common stock -- (13)
Dividends paid on common stock (8) (7)(16) (13)
Dividends paid on preferred stock (2) (2)
Decrease in long-term other liabilities -- (5) ------------ ------------(5)
---------- ----------
Net cash provided by (used in) financing activities 1,762 (50)
------------ ------------887 117
---------- ----------
Effect of exchange rate changes on cash 1 (1) ------------ ------------(1)
---------- ----------
Net increase in cash and cash equivalents 174 382240 223
Cash and cash equivalents at beginning of period 193 228
------------ ------------185 204
---------- ----------
Cash and cash equivalents at end of period $ 367 610
============ ============425 427
========== ==========
See accompanying notes to consolidated financial statements.
78
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying consolidated financial statements and notes thereto of
Devon Energy Corporation ("Devon") have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. Accordingly, certain footnote
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 consolidated financial statements and notes
thereto should be read in conjunction with the consolidated financial statements
and notes thereto included in Devon's 2001 Annual Report on Form 10-K.
In the opinion of Devon's management, all adjustments (all of which are
normal and recurring) have been made which are necessary to fairly state the
consolidated financial position of Devon and its subsidiaries as of March 31,June 30,
2002, and the results of their operations and their cash flows for the
three
monththree-month and six-month periods ended March 31,June 30, 2002 and 2001. Certain of the
2001 amounts in the accompanying consolidated financial statements have been
reclassified to conform to the 2002 presentation.
2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION
Mitchell Energy & Development Corp. Merger
On January 24, 2002, Devon completed its acquisition of Mitchell Energy
& Development Corp. ("Mitchell"). Under the terms of this merger, Devon issued
approximately 30 million shares of Devon common stock and paid $1.6 billion in
cash to the Mitchell stockholders. The cash portion of the acquisition was
funded from borrowings under a $3.0 billion senior unsecured term loan credit
facility (see Note 3).
Devon acquired Mitchell for the significant development and
exploitation projects in each of Mitchell's core areas, increased marketing and
midstream operations and increased exposure to the North American natural gas
market.
The calculation of the purchase price and the preliminary allocation to
assets and liabilities as of January 24, 2002, are shown below. The purchase
price allocation is preliminary because certain items such as the determination
of the final tax bases and fair value of the assets and liabilities as of the
acquisition date have not been completed.
8are subject to change.
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(IN MILLIONS,
EXCEPT SHARE PRICE)
-------------------
Calculation and preliminary allocation of purchase price:
Shares of Devon common stock issued to Mitchell stockholders 30
Average Devon stock price $ 50.95
--------------------
Fair value of common stock issued $ 1,512
Cash paid to Mitchell stockholders, calculated at $31 per outstanding
common share of Mitchell 1,573
--------------------
Fair value of Devon common stock and cash to be issued to Mitchell
stockholders 3,085
Plus estimated acquisition costs incurred 90
Plus fair value of Mitchell employee stock options assumed by Devon 27
--------------------
Total purchase price 3,202
Plus fair value of liabilities assumed by Devon:
Current liabilities 177
Long-term debt 506
Other long-term liabilities 129
Deferred income taxes 799
--------------------
Total purchase price plus liabilities assumed $ 4,813
====================
Fair value of assets acquired by Devon:
Current assets 169
Proved oil and gas properties 1,535
Unproved oil and gas properties 639
Gas services facilities and equipment 1,000
Other property and equipment 14
Other assets 83
Goodwill (none deductible for income taxes) 1,373
--------------------
Total fair value of assets acquired $ 4,813
====================
Anderson Exploration Ltd. Acquisition
On October 12, 2001, Devon accepted all of the Anderson common shares
tendered by Anderson stockholders in the tender offer, which represented
approximately 97% of the outstanding Anderson common shares. On October 17,
2001, Devon completed its acquisition of Anderson by a compulsory acquisition
under the Canada Business Corporations Act of the remaining 3% of Anderson
common shares. The cost to Devon of acquiring Anderson's outstanding common
shares and paying for the intrinsic value of Anderson's outstanding options and
appreciation rights was approximately $3.5 billion, which was funded from the
sale of $3.0 billion of debt securities and borrowings under a $3.0 billion
senior unsecured term loan credit facility (see Note 3).
Pro Forma Information
Set forth in the following table is certain unaudited pro forma
financial information for the three-monthsix-month periods ended March 31,June 30, 2002 and 2001.
The information for the three-monthsix-month periods ended March 31,June 30, 2002 and 2001, has been
prepared assuming the Anderson acquisition and the Mitchell merger were
consummated on January 1, 2001. All pro forma information is based on estimates
and assumptions deemed appropriate by Devon. The pro forma information is
presented for illustrative purposes only. If the transactions had occurred in
the past, Devon's operating results might have been different from those
presented in the following table. The pro forma information should not be relied
upon as an indication of the operating results that Devon would have achieved if
the transactions had occurred on January 1, 2001. The pro forma information also
should not be used as an indication of the future results that Devon will
achieve after the transactions.
910
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following should be considered in connection with the pro forma
financial information presented:
- On February 12, 2001, Anderson acquired all of the outstanding shares
of Numac Energy Inc. The summary unaudited pro forma combined statements of
operations do not include any results from Numac's operations prior to February
12, 2001.
- Anderson had a compensation plan pursuant to which it periodically
issued awards referred to as share appreciation rights under which employees
could earn compensation based on increases in the market price of Anderson's
stock. Anderson awarded these rights in lieu of stock option grants. Pro forma
general and administrative expenses reported in the accompanying unaudited pro
forma statements of operations for the three-month period ended March 31, 2001
include $3 million of expenses related to these plans. After taxes, these plans
had the effect of decreasing unaudited pro forma net earnings in the 2001 period
by $2 million. Devon acquired all outstanding rights as part of the Anderson
acquisition. Accordingly, these rights will not affect Devon's net earnings
subsequent to the closing of the Anderson acquisition.
- Mitchell has compensation plans pursuant to which it periodically
issued awards referred to as "bonus units" under which employees could earn
compensation based on increases in the market price of Mitchell common stock.
Mitchell generally awarded these bonus units in lieu of stock option grants. Pro
forma general and administrative expenses reported in the accompanying unaudited
pro forma statements of operations for the three-month periods ended March 31,
2002 and 2001 include $2 million of income and $1 million of expenses,
respectively related to these plans. After taxes, these plans had the effect of
decreasing unaudited pro forma net earnings in the 2002 period by $1 million and
increasing unaudited pro forma net earnings in the 2001 period by $1 million.
Devon will not issue such bonus units after the merger.
- Devon's historical results of operations for the three-monthsix-month period
ended March 31,June 30, 2001 include $8$17 million of amortization expense for goodwill
related to previous mergers. As of January 1, 2002, in accordance with new
accounting pronouncements, such goodwill is no longer amortized, but instead
will be tested for impairment at least annually. No goodwill amortization
expense has been recognized in the pro forma statements of operations for the
goodwill related to the Anderson acquisition and the Mitchell merger.
1011
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PRO FORMA INFORMATION
THREESIX MONTHS ENDED MARCH 31JUNE 30
--------------------------
(IN MILLIONS, EXCEPT PER
SHARE AMOUNTS AND
PRODUCTION VOLUMES)
2002 2001
------------ ---------------------- ----------
REVENUES
Oil sales $ 256497 $ 335598
Gas sales 490 1,2411,054 2,086
Natural gas liquids sales 61 95132 174
Marketing and midstream revenue 230 434
------------ ------------497 757
---------- ----------
Total revenues 1,037 2,105
------------ ------------2,180 3,615
---------- ----------
PRODUCTION AND OPERATING COSTS AND EXPENSES
Lease operating expenses 174 187329 357
Transportation costs 41 3679 75
Production taxes 23 5758 95
Marketing and midstream costs and expenses 189 387412 672
Depreciation, depletion and amortization of property and equipment 339 315662 633
Amortization of goodwill -- 817
General and administrative expenses 55 45
Expenses related to mergers -- --109 95
Reduction of carrying value of oil and gas properties -- --
------------ ------------651 77
---------- ----------
Total production and operating costs and expenses 821 1,035
------------ ------------2,300 2,021
---------- ----------
Earnings (loss) from operations 216 1,070(120) 1,594
OTHER INCOME (EXPENSES)
Interest expense (125) (121)(273) (242)
Effects of changes in foreign currency exchange rates (4) (13)12 5
Change in fair value of financial instruments (17) (41)7 (20)
Other income 15 7
------------ ------------21 18
---------- ----------
Net other expenses (131) (168)
------------ ------------(233) (239)
---------- ----------
Earnings (loss) from continuing operations before income tax expense (benefit)
and cumulative effect of change in accounting principle 85 902(353) 1,355
INCOME TAX EXPENSE (BENEFIT)
Current 1 18587 192
Deferred 22 173
------------ ------------(294) 326
---------- ----------
Total income tax expense 23 358
------------ ------------(benefit) (207) 518
---------- ----------
Earnings (loss) from continuing operations before cumulative effect of change in
accounting principle 62 544(146) 837
DISCONTINUED OPERATIONS
Results of discontinued operations before income taxes (including gain on disposal
of $97 million in 2002) 108 35
Total income tax expense 4 15
---------- ----------
Net results of discontinued operations 104 20
---------- ----------
Earnings (loss) before cumulative effect of change in accounting principle (42) 857
Cumulative effect of change in accounting principle -- 49
------------ ---------------------- ----------
Net earnings 62 593(loss) (42) 906
Preferred stock dividends 2 2
------------ ------------5 5
---------- ----------
Net earnings (loss) applicable to common stockholders $ 60(47) $ 591
============ ============
Net901
========== ==========
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PRO FORMA INFORMATION
SIX MONTHS ENDED JUNE 30
--------------------------
(IN MILLIONS, EXCEPT PER
SHARE AMOUNTS AND
PRODUCTION VOLUMES)
2002 2001
---------- ----------
Basic earnings before cumulative(loss) per average common share outstanding:
Earnings (loss) from continuing operations $ (0.97) 5.26
Earnings from discontinued operations $ 0.67 0.12
Cumulative effect of change in accounting principle -- 0.31
---------- ----------
Net earnings (loss) $ (0.30) 5.69
========== ==========
Diluted earnings (loss) per average common share outstanding:
BasicEarnings (loss) from continuing operations $ 0.38(0.97) 5.07
Earnings from discontinued operations $ 3.43
============ ============
Diluted $ 0.38 $ 3.29
============ ============0.67 0.12
Cumulative effect of change in accounting principle -- 0.30
---------- ----------
Net earnings per average common share outstanding:
Basic(loss) $ 0.38 $ 3.74
============ ============
Diluted $ 0.38 $ 3.59
============ ============(0.30) 5.49
========== ==========
Weighted average common shares outstanding - basic 156 158
============ ====================== ==========
Weighted average common shares outstanding - diluted 158162 165
============ ====================== ==========
Production volumes:
Oil (MMBbls) 14 1424 28
Gas (Bcf) 205 192404 392
NGLs (MMBbls) 5 411 8
MMBoe 53 50102 101
11
3. LONG-TERM DEBT
$3 Billion Term Loan Credit Facility
Prior to December 31, 2001, Devon used proceeds of $1 billion on thisof its $3
billion term loan credit facility to partially fund the Anderson acquisition.
The remaining $2 billion of availability was utilized upon the closing of the
Mitchell acquisition on January 24, 2002. As of March 31,June 30, 2002, $2.1$1.7 billion remainedof
the balance outstanding under
this term loan credit facility.was retired. The sourceprimary sources of the repayments made during the
quarter were from
the issuance of $1 billion of debt securities discussed below and $100$896 million
from the sale of certain oil and gas properties. Additional repaymentsWith the proceeds from
additional property sales through July 31, 2002, the term loan balance has been
further reduced by $153 million. The term loan's balance as of $445 million from the sale of certain properties have been made between April 1,July 31, 2002,
and May 3, 2002.was $1.1 billion.
Debt Securities
On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15,
2032. The net proceeds received, after discounts and issuance costs, were $986
million. The debt securities are unsecured and unsubordinated obligations of
Devon. The net proceeds from the issuance of these debt securities were partially used to pay down $820 million on theDevon's
$3 billion term loan credit facility. The remaining $166 million of net proceeds
net of discounts and issuance costs, will bewas used in June 2002 to partially fund the early extinguishment of $175 million
of 8.75% senior notes due June 15, 2007. The notes are redeemable by Devon on June 15, 2002,were redeemed at 104.375% of
principal, or approximately $183 million.
Commercial Paper
As of March 31,June 30, 2002, Devon had $156$315 million of borrowings under its
commercial paper program at an average rate of 2.6%2.3%. Because Devon has the
intent and ability to refinance the balance due with borrowings under its Credit
Facilities,credit
facilities, the $156$315 million outstanding under the commercial paper program was
classified as long-term debt on the March 31,June 30, 2002 consolidated balance sheet.
Revolving13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amendment of Existing Credit Facilities
Devon has $1 billion of unsecured long-term credit facilities (the
"Credit Facilities"). The Credit Facilities include a U.S. facility of $725
million (the "U.S. Facility") and a Canadian facility of $275 million (the
"Canadian Facility"). The $725 million U.S. Facility consists of a Tranche A
facility of $200 million and a Tranche B facility of $525 million. On June 7,
2002, Devon renewed the $525 million Tranche B facility and its $275 million
Canadian facility.
The Tranche A facility matures on October 15, 2004. Devon may borrow
funds under the Tranche B facility until June 5, 2003 (the "Tranche B Revolving
Period"). Devon may request that the Tranche B Revolving Period be extended an
additional 364 days by notifying the agent bank of such request between 30 and
60 days prior to the end of the Tranche B Revolving Period. On June 6, 2003, at
the end of the Tranche B Revolving Period, Devon may convert the then
outstanding balance under the Tranche B facility to a two-year term loan by
paying the Agent a fee of 12.5 basis points. The applicable borrowing rate would
be at LIBOR plus 125 basis points. On June 30, 2002, there were no borrowings
outstanding under the $725 million U.S. Facility. The available capacity under
the U.S. Facility as of June 30, 2002, net of commercial paper borrowings, was
$410 million.
Devon may borrow funds under the $275 million Canadian Facility until
June 5, 2003 (the "Canadian Facility Revolving Period"). Devon may request that
the Canadian Facility Revolving Period be extended an additional 364 days by
notifying the agent bank of such request between 30 and 60 days prior to the end
of the Canadian Facility Revolving Period. Debt outstanding as of the end of the
Canadian Facility Revolving Period is payable in semiannual installments of 2.5%
each for the following five years, with the final installment due five years and
one day following the end of the Canadian Facility Revolving Period. On June 30,
2002, there were no borrowings under the $275 million Canadian facility.
Under the terms of the Credit Facilities, Devon has the right to
reallocate up to $100 million of the unused Tranche B facility maximum credit
amount to the Canadian Facility. Conversely, Devon also has the right to
reallocate up to $100 million of unused Canadian Facility maximum credit amount
to the Tranche B Facility.
Amounts borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon may elect for periods up to six months. Such rates
are generally less than the prime rate. Devon may also elect to borrow at the
prime rate. The Credit Facilities provide for an annual facility fee of $1.4
million that is payable quarterly.
The agreements governing the Credit Facilities contain certain
covenants and restrictions, including a maximum allowed debt-to-capitalization
ratio as defined in the agreements.
Letter of Credit Facility
On July 25, 2002, Devon renewed and increased its letter of credit and
revolving bank facility ("LOC Facility") for its Canadian operations. This C$150
million LOC Facility will be used primarily by Devon's wholly-owned
subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to
issue letters of credit. As of MarchJuly 31, 2002, Devon had $13C$104 million of borrowingsletters of credit
were issued under itsthe LOC Facility primarily for Canadian facility at an average rate of 3.8%.drilling commitments.
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Devon has periodically entered into oil and gas financial instruments
and foreign exchange rate swaps to manage its exposure to oil and gas price
volatility. The foreign exchange rate swaps mitigate the effect of volatility in
the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues that are
predominantly based on U.S. dollar prices. The hedging instruments are usually
placed with counterparties that Devon believes are minimal credit risks. It is
Devon's policy to only enter into derivative contracts with investment grade
rated counterparties deemed by management to be competent and competitive market
makers. The oil 12
and gas reference prices upon which the price hedging
instruments are based reflect various market indices that have a high degree of
historical correlation with actual prices received by Devon.
As of March 31,June 30, 2002, $35$15 million of net deferred losses on derivative
instruments in "accumulated other comprehensive loss"income (loss)" are expected to
be reclassified to earnings from operations during the next 12 months.
Transactions and events expected to occur over the next 12 months that will
necessitate reclassifying these derivatives' losses to earnings from operations
are primarily the production and sale of the hedged oil and gas which includes the production
hedged under the various derivative instruments.quantities. The
maximum term over which Devon is hedging exposures to the variability of cash
flows for commodity price risk is 2130 months.
Devon recorded in its statements of operations a lossgain of $17$24 million
and $14$7 million in the firstsecond quarter of 2002 and 2001, respectively, and a gain
of $7 million and a loss of $7 million in the six-month periods ended June 30,
2002 and 2001, respectively, for the change in fair value of derivative
instruments that do not qualify for hedge accounting treatment.treatment, as well as the
ineffectiveness of derivatives that do qualify as hedges. Included in the
first quarterthree-month and six-month periods ended June 30, 2002 loss are net gains of
approximately $7$3 million and $10 million, respectively, related to such
ineffectiveness. These gains are related to both (i) the ineffectiveness of the
various cash flow hedges and (ii) the component of the derivative instrument
gain or loss excluded from the assessment of hedge effectiveness.
5. GOODWILL
Effective January 1, 2002, Devon adopted the remaining provisions of
Statement of Financial Accounting Standards No. 142, Goodwill and Other
Intangible AssetAssets (SFAS No. 142). Under SFAS No. 142, goodwill and intangible
assets with indefinite useful lives are no longer amortized, but are instead
tested for impairment at least annually.
Devon will perform an assessment of the fair value of the recorded
goodwill as of January 1, 2002. Devon has until June 30, 2002, to determine the
fair value of its reporting units and compare such fair value to each reporting
unit's carrying value. To the extent a reporting unit's carrying value exceeds
its fair value, an indication exists that the reporting unit's goodwill may be
impaired and Devon must perform the second step of the transitional impairment
test. In the second step, Devon must compare the implied fair value of the
reporting unit's goodwill, determined by allocating the reporting unit's fair
value to all of it assets (recognized and unrecognized) and liabilities in a
manner similar to a purchase price allocation in accordance with SFAS No. 141,
Business Combinations, to its carrying value, both of which would be measured as
of January 1, 2002. This second step is required to be completed as soon as
possible, but no later than the end of 2002. Any transitional impairment will be
recognized as the cumulative effect of a change in accounting principle in
Devon's 2002 statement of operations.
As of January 1, 2002, Devon had unamortized goodwill in the amount of
$2.2 billion, which was subject to the transition goodwill impairment assessment
provisions of SFAS No. 142. Devon has not completed its assessment of the fair value
of its reporting units and compared such fair value to each reporting unit's
carrying value, including goodwill, as of January 1, 2002. Based on this
assessment, no transitional impairment assessment as of March 31, 2002. However, Devon does not expect that a
transitional impairment will be required to be recognized.
13
the carrying value of goodwill was
required.
As a result of the January 2002 Mitchell acquisition, goodwill
increased $1.4 billion to $3.6 billion at March 31, 2002.billion. All of the Mitchell-related goodwill is recorded in
Devon's U.S. segment.
Following is a reconciliation of reported net income and the related
earnings per share amounts
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assuming the provisions of SFAS No. 142 had been adopted as of January 1, 2001.
FOR THE THREE MONTHS ENDED
MARCH 31,JUNE 30,
2002 2001
------------- ----------------------- ----------
(IN MILLIONS)
Net earnings (loss) applicable to common shareholders, as reported $ 60 398(107) 133
Add back amortization of goodwill -- 8
------------- -------------9
---------- ----------
Net earnings (loss) applicable to common shareholders, as adjusted 60 406
============= =============$ (107) 142
========== ==========
Basic earnings (loss) per share:
Net earnings (loss) applicable to common shareholders, as reported $ 0.41 3.08(0.68) 1.03
Amortization of goodwill -- 0.07
------------- ----------------------- ----------
Net earnings (loss) applicable to common shareholders, as adjusted $ 0.41 3.15
============= =============(0.68) 1.10
========== ==========
Diluted earnings (loss) per share:
Net earnings (loss) applicable to common shareholders, as reported $ 0.40 2.96(0.68) 1.01
Amortization of goodwill -- 0.07
------------- ----------------------- ----------
Net earnings (loss) applicable to common shareholders, as adjusted $ 0.40 3.03
============= =============(0.68) 1.08
========== ==========
FOR THE SIX MONTHS ENDED
JUNE 30,
2002 2001
---------- ----------
(IN MILLIONS)
Net earnings (loss) applicable to common shareholders, as reported $ (47) 531
Add back amortization of goodwill -- 17
---------- ----------
Net earnings (loss) applicable to common shareholders, as adjusted $ (47) 548
========== ==========
Basic earnings (loss) per share:
Net earnings (loss) applicable to common shareholders, as reported $ (0.31) 4.11
Amortization of goodwill -- 0.13
---------- ----------
Net earnings (loss) applicable to common shareholders, as adjusted $ (0.31) 4.24
========== ==========
Diluted earnings (loss) per share:
Net earnings (loss) applicable to common shareholders, as reported $ (0.31) 3.96
Amortization of goodwill -- 0.13
---------- ----------
Net earnings (loss) applicable to common shareholders, as adjusted $ (0.31) 4.09
========== ==========
6. EARNINGS PER SHARE
The following tables reconciletable reconciles the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
the three-month and six-month periods ended March 31, 2002 andJune 30, 2001. Options to purchase approximately 3.4 million shares of Devon's common
stock with exercise prices ranging from $42.41The diluted loss per
share to $89.66 per share
(with a weighted average price of $53.63 per share) were outstanding at March
31, 2002, but were not included in the computation of diluted earnings per sharecalculations for the first quarter ofthree-month and six-month periods ended June 30, 2002
because the options' exercise price exceeded the
average market price of Devon's common stock during the first quarter.
Similarly, options to purchase approximately 0.8 million shares of Devon's
common stock with exercise prices ranging from $58.84 per share to $89.66 per
share (with a weighted average price of $66.49 per share) were excluded from theproduce results that are anti-dilutive. (The diluted earnings per share calculation for the first quarter of 2001.three
months ended June 30, 2002 reduced the net loss by $2 million and increased the
common shares outstanding by 6 million shares. The excluded optionsdiluted calculation for the
six months ended June 30, 2002 period expire between April 10,reduced the net loss by $5 million and increased
the common shares outstanding by 6 million shares.) Therefore, the diluted loss
per share amounts for the three-month and six-month periods
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ended June 30, 2002 and December
4, 2011.
14
reported in the accompanying consolidated statements of
operations are the same as the basic loss per share amounts.
NET EARNINGS NET
APPLICABLE COMMON EARNINGS
TO COMMON SHARES PER
STOCKHOLDERS OUTSTANDING SHARE
------------- ------------- ------------------------- ------------ --------
(IN MILLIONS)
THREE MONTHS ENDED MARCH 31, 2002:
Basic earnings per share $ 60 148 $ 0.41
=============
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options -- 2
------------- -------------
Diluted earnings per share $ 62 150 $ 0.40
============= ============= =============
THREE MONTHS ENDED MARCH 31,JUNE 30, 2001:
Basic earnings per share $ 398133 129 $ 3.08
=============1.03
========
Dilutive effect of:
Potential common shares issuable upon conversion
of senior convertible debentures (the increase in net
earnings is net of income tax expense of $1 million) 2$1) 3 4
Potential common shares issuable upon the exercise
of outstanding stock options -- 2
------------- ------------------------- ------------
Diluted earnings per share $ 400136 135 $ 2.96
============= ============= =============1.01
============ ============ ========
SIX MONTHS ENDED JUNE 30, 2001:
Basic earnings per share $ 531 129 $ 4.11
========
Dilutive effect of:
Potential common shares issuable upon conversion
of senior convertible debentures (the increase in net
earnings is net of income tax expense of $2) 5 4
Potential common shares issuable upon the exercise
of outstanding stock options -- 2
------------ ------------
Diluted earnings per share $ 536 135 $ 3.96
============ ============ ========
All options to purchase Devon common stock were excluded from the
diluted earnings per share calculations for the 2002 periods because of the
anti-dilutive effect of such options. Options to purchase approximately 1.0
million shares of Devon's common stock with exercise prices ranging from $56.76
per share to $89.66 per share (with a weighted average price of $65.31 per
share) were excluded from the diluted earnings per share calculation for the
second quarter of 2001.
Options to purchase approximately 1.0 million shares of Devon's common
stock, with exercise prices from $57.72 to $89.66 per share (with a weighted
average price of $65.34 per share) were excluded from the diluted earnings per
share calculation for the first six months of 2001.
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES
Under the full cost method of accounting, the net book value of oil and
gas properties less related deferred income taxes (the "costs to be recovered"),
may not exceed a calculated "full cost ceiling." The senior convertible debenturesceiling limitation is the
discounted estimated after-tax future net revenues from oil and gas properties.
The ceiling is imposed separately by country. In calculating future net
revenues, current prices and costs are generally held constant indefinitely, and
Devon does not include the effect of hedges in the calculation of the future net
revenues. Therefore, the ceiling limitation is not necessarily indicative of the
properties' fair value. The costs to be recovered are compared to the ceiling on
a quarterly basis. If the costs to be recovered exceed the ceiling, the excess
is written off as an expense.
An expense recorded in one period may not be reversed in a subsequent
period even though higher oil and gas prices may have increased the ceiling
applicable to the subsequent period.
Based on oil and natural gas cash market prices as of June 30, 2002,
Devon's Canadian costs to be recovered exceeded the related ceiling value by
$371 million. This after-tax amount resulted in a pre-tax reduction of the
carrying value of Devon's Canadian oil and gas properties of $651 million in the
second quarter of 2002. This reduction was the result of a sharp drop in
Canadian gas prices during the last half of June 2002. The June 30, 2002,
reference prices used in the Canadian ceiling calculation, expressed in Canadian
dollars, were a NYMEX price of C$40.79 per barrel of oil and an AECO price of
C$2.17 per Mcf of gas. The cash market prices of natural gas increased during
the month of July 2002 prior to Devon's release of its second quarter results,
but the increase was not sufficient to offset the entire reduction calculated as
of June 30.
8. DISCONTINUED OPERATIONS
Effective January 1, 2002, Devon was required to adopt SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes
both SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of and the accounting and reporting provisions
of APB Opinion No. 30, Reporting the Results of Operations-Reporting the Effects
of Disposal of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions, for the disposal of a segment of
a business (as previously defined in that Opinion).
On April 18, 2002, Devon, sold its Indonesian operations to PetroChina
Company Limited for total cash consideration of $262 million. Devon received
approximately $250 million upon closing. An additional $12 million could be
received upon successful completion of certain events. In accordance with SFAS
No. 144, Devon has reclassified the assets, liabilities and results
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of its Indonesian operations, which were included in Devon's International
segment, as discontinued operations for each of the 2002 dilution
calculation becauseperiods presented. The
following tables include the inclusion was anti-dilutive.
7.major classes of assets and liabilities and the
revenues that were reclassified.
JUNE 30, DECEMBER 31,
2002 2001
------------ ------------
(IN MILLIONS)
MAJOR CLASSES OF ASSETS AND LIABILITIES
Cash -- $ 8
Accounts receivable -- 34
Inventories -- 15
Other current assets -- 2
Property and equipment, net of accumulated depreciation,
depletion and amortization -- 145
Other assets -- 8
------------ ------------
Total assets -- 212
============ ============
Accounts payable - trade -- 25
Income taxes payable -- 13
Accrued expense -- 1
Other liabilities -- 7
Deferred income taxes -- 31
------------ ------------
Total liabilities -- 77
============ ============
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------------- ---------------------------
2002 2001 2002 2001
------ ------ ------ ------
(IN MILLIONS)
REVENUES
Oil sales $ 5 26 $ 26 62
NGL sales -- -- 1 --
------ ------ ------ ------
Total revenues 5 26 $ 27 62
====== ====== ====== ======
9. SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments (refunds) for interest and income taxes in the first quartersix
months of 2002 and 2001 were
approximately $185 million and $25 million, respectively. Cash receipts for
federal, state and foreign income taxes in first quarter 2002 were approximately
$89 million. Cash payments for federal, state and foreign income taxes in 2001
were approximately $47 million.
15are presented below:
FOR THE SIX MONTHS ENDED
JUNE 30,
----------------------------
2002 2001
------ ------
(IN MILLIONS)
Interest paid $ 323 69
Income taxes paid (refunded) (86) 159
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The first quarter 2002 Mitchell acquisition involved non-cash consideration as
presented below:
2002
-----------------------
(IN MILLIONS)
Value of common stock issued $ 1,512
Employee stock options assumed 27
Liabilities assumed 812
Deferred tax liability created 799
---------
Fair value of assets----------
Assets acquired with non-cash consideration $ 3,150
===================
8.10. SEGMENT INFORMATION
Devon manages its business by country. As such, Devon identifies its
segments based on geographic areas. Devon has three reportable segments: its operations in
the U.S., its operations in Canada and its international operations outside of
North America. Substantially all of these segments' operations involve oil and
gas producing and marketing and midstream activities. Following is certain
financial information regarding Devon's segments for the first quarters of 2002
and 2001.segments. The revenues reported are all
from external customers.
INTER-
U.S. CANADA NATIONAL TOTAL
------------ ------------ ------------ -------------------- -------- -------- --------
(IN MILLIONS)
AS OF MARCH 31,JUNE 30, 2002:
Current assets $ 766 140 264 1,170595 139 427 1,161
Property and equipment, net of accumulated depreciation,
depletion and amortization 7,153 4,378 732 12,2636,849 3,639 599 11,087
Investment in ChevronTexaco Corporation common stock 640628 -- -- 640628
Goodwill, net of amortization 1,582 1,9242,019 69 3,5753,670
Other assets 285282 34 10 329
------------ ------------ ------------ ------------11 327
-------- -------- -------- --------
Total assets $ 10,426 6,476 1,075 17,977
============ ============ ============ ============9,936 5,831 1,106 16,873
======== ======== ======== ========
Current liabilities 559 353 149 1,061391 540 128 1,059
Other liabilities 274279 7 11 2923 289
Debentures exchangeable into shares of ChevronTexaco
Corporation common stock 652655 -- -- 652655
Other long-term debt 3,603 4,6333,236 4,141 -- 8,2367,377
Deferred revenue 3317 -- -- 3317
Fair value of financialderivative instruments 64 541 6 -- 6947
Deferred income taxes 1,559 1,320 64 2,9431,498 1,125 22 2,645
Stockholders' equity 3,682 158 851 4,691
------------ ------------ ------------ ------------3,819 12 953 4,784
-------- -------- -------- --------
Total liabilities and stockholders' equity $ 10,426 6,476 1,075 17,977
============ ============ ============ ============9,936 5,831 1,106 16,873
======== ======== ======== ========
1620
8.DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. SEGMENT INFORMATION (CONTINUED)
INTER-
U.S. CANADA NATIONAL TOTAL
---------- ---------- ---------- ------------------ -------- -------- --------
(IN MILLIONS)
THREE MONTHS ENDED MARCH 31,JUNE 30, 2002:
REVENUES
Oil sales $ 130 82 42 254148 90 24 262
Gas sales 303 163377 185 2 468564
Natural gas liquids sales 35 20 1 5651 21 -- 72
Marketing and midstream revenues 158 2revenue 262 5 -- 160
---------- ---------- ---------- ----------267
-------- -------- -------- --------
Total revenues 626 267 45 938
---------- ---------- ---------- ----------838 301 26 1,165
-------- -------- -------- --------
PRODUCTION AND OPERATING COSTS AND EXPENSES
Lease operating expenses 91 61 18 17096 62 8 166
Transportation costs 22 1626 12 -- 38
Production taxes 21 1 -- 2231 2 2 35
Marketing and midstream costs and expenses 125218 4 -- -- 125222
Depreciation, depletion and amortization of property
and equipment 204 105 11 320220 102 5 327
General and administrative expenses 3542 9 5 49
---------- ---------- ---------- ----------3 54
Reduction of carrying value of oil and gas properties -- 651 -- 651
-------- -------- -------- --------
Total production and operating costs and expenses 498 192 34 724
---------- ---------- ---------- ----------633 842 18 1,493
-------- -------- -------- --------
Earnings (loss) from operations 128 75 11 214205 (541) 8 (328)
OTHER INCOME (EXPENSES)
Interest expense (49) (73) (2) (124)(75) -- (148)
Effects of changes in foreign currency exchange rates -- 17 (1) (3) (4)16
Change in fair value of financial instruments (20) 325 (1) -- (17)24
Other income 9 3 3 156 (1) 1 6
-------- -------- -------- --------
Net other expenses (42) (60) (68) (2) (130)
---------- ---------- ---------- ------------ (102)
-------- -------- -------- --------
Earnings (loss) from continuing operations before income
tax expense 68 7 9 84(benefit) 163 (601) 8 (430)
INCOME TAX EXPENSE (BENEFIT)
Current 668 8 1 (6) 177
Deferred 5 3 13 21
---------- ---------- ---------- ----------(47) (259) 2 (304)
-------- -------- -------- --------
Total income tax expense 11 4 7 22
---------- ---------- ---------- ----------(benefit) 21 (251) 3 (227)
-------- -------- -------- --------
Earnings (loss) from continuing operations 142 (350) 5 (203)
DISCONTINUED OPERATIONS
Results of discontinued operations before income taxes -- -- 100 100
Income tax expense -- -- 1 1
-------- -------- -------- --------
Net results of discontinued operations -- -- 99 99
-------- -------- -------- --------
Net earnings 57 3 2 62(loss) 142 (350) 104 (104)
Preferred stock dividends 23 -- -- 2
---------- ---------- ---------- ----------3
-------- -------- -------- --------
Net earnings (loss) applicable to common shareholders $ 55 3 2 60
========== ========== ========== ==========139 (350) 104 (107)
======== ======== ======== ========
Capital expenditures including acquisitions of businesses $ 1,922 239 29 2,190
========== ========== ========== ==========302 56 28 386
======== ======== ======== ========
1721
8.DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. SEGMENT INFORMATION (CONTINUED)
INTER-
U.S. CANADA NATIONAL TOTAL
---------- ---------- ---------- ------------------ -------- -------- --------
(IN MILLIONS)
THREE MONTHS ENDED MARCH 31,JUNE 30, 2001:
REVENUES
Oil sales $ 166 28 60 254144 29 36 209
Gas sales 643 79388 52 3 725443
Natural gas liquids sales 27 528 4 -- 32
Marketing and midstream revenues 18 2revenue 12 3 -- 20
---------- ---------- ---------- ----------15
-------- -------- -------- --------
Total revenues 854 114 63 1,031
---------- ---------- ---------- ----------572 88 39 699
-------- -------- -------- --------
PRODUCTION AND OPERATING COSTS AND EXPENSES
Lease operating expenses 89 15 19 12379 17 11 107
Transportation costs 1416 3 -- 1719
Production taxes 44 129 -- 45-- 29
Marketing and midstream costs and expenses 15 110 2 -- 1612
Depreciation, depletion and amortization of property
and equipment 149 19 15 183147 20 13 180
Amortization of goodwill 89 -- -- 89
General and administrative expenses 2025 2 (1) 26
Reduction of carrying value of oil and gas properties -- 22
---------- ---------- ---------- ------------ 77 77
-------- -------- -------- --------
Total production and operating costs and expenses 339 41 34 414
---------- ---------- ---------- ----------315 44 100 459
-------- -------- -------- --------
Earnings (loss) from operations 515 73 29 617257 44 (61) 240
OTHER INCOME (EXPENSES)
Interest expense (32) (2) -- (34)(33) (1) (1) (35)
Change in fair value of financial instruments (14)7 -- -- (14)7
Other income (expense) 9 (2) 5 12
-------- -------- -------- --------
Net other income (expenses) (17) (3) 4 (16)
-------- -------- -------- --------
Earnings (loss) from continuing operations before income
tax expense (benefit) 240 41 (57) 224
INCOME TAX EXPENSE (BENEFIT)
Current (8) -- 5 (3)
Deferred 97 15 (12) 100
-------- -------- -------- --------
Total income tax expense (benefit) 89 15 (7) 97
-------- -------- -------- --------
Earnings (loss) from continuing operations 151 26 (50) 127
DISCONTINUED OPERATIONS
Results of discontinued operations before income taxes -- -- 16 16
Total income tax expense -- -- 7 7
-------- -------- -------- --------
Net results of discontinued operations -- -- 9 9
-------- -------- -------- --------
Net earnings (loss) 151 26 (41) 136
Preferred stock dividends 3 -- -- 3
-------- -------- -------- --------
Net earnings (loss) applicable to common shareholders $ 148 26 (41) 133
======== ======== ======== ========
Capital expenditures, including acquisitions of businesses $ 566 49 57 672
======== ======== ======== ========
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. SEGMENT INFORMATION (CONTINUED)
INTER-
U.S. CANADA NATIONAL TOTAL
-------- -------- -------- --------
(IN MILLIONS)
SIX MONTHS ENDED JUNE 30, 2002:
REVENUES
Oil sales $ 278 172 45 495
Gas sales 680 348 4 1,032
Natural gas liquids sales 86 41 -- 127
Marketing and midstream revenue 420 7 -- 427
-------- -------- -------- --------
Total revenues 1,464 568 49 2,081
-------- -------- -------- --------
PRODUCTION AND OPERATING COSTS AND EXPENSES
Lease operating expenses 187 123 15 325
Transportation costs 48 28 -- 76
Production taxes 52 3 2 57
Marketing and midstream costs and expenses 343 4 -- 347
Depreciation, depletion and amortization of property
and equipment 424 208 11 643
General and administrative expenses 77 18 9 104
Reduction of carrying value of oil and gas properties -- (3) 8
---------- ---------- ---------- ----------651 -- 651
-------- -------- -------- --------
Total production and operating costs and expenses 1,131 1,035 37 2,203
-------- -------- -------- --------
Earnings (loss) from operations 333 (467) 12 (122)
OTHER INCOME (EXPENSES)
Interest expense (122) (148) (2) (272)
Effects of changes in foreign currency exchange rates -- 16 (4) 12
Change in fair value of financial instruments 5 2 -- 7
Other income 15 2 4 21
-------- -------- -------- --------
Net other expenses (35)(102) (128) (2) (3) (40)
---------- ---------- ---------- ----------(232)
-------- -------- -------- --------
Earnings (loss) from continuing operations before income
tax expense (benefit) 231 (595) 10 (354)
INCOME TAX EXPENSE (BENEFIT)
Current 74 9 4 87
Deferred (42) (256) 3 (295)
-------- -------- -------- --------
Total income tax expense (benefit) 32 (247) 7 (208)
-------- -------- -------- --------
Earnings (loss) from continuing operations 199 (348) 3 (146)
DISCONTINUED OPERATIONS
Results of discontinued operations before income taxes -- -- 108 108
Total income tax expense -- -- 4 4
-------- -------- -------- --------
Net results of discontinued operations -- -- 104 104
-------- -------- -------- --------
Net earnings(loss) 199 (348) 107 (42)
Preferred stock dividends 5 -- -- 5
-------- -------- -------- --------
Net earnings (loss) applicable to common shareholders $ 194 (348) 107 (47)
======== ======== ======== ========
Capital expenditures, including acquisitions of businesses $ 2,224 295 53 2,572
======== ======== ======== ========
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. SEGMENT INFORMATION (CONTINUED)
INTER-
U.S. CANADA NATIONAL TOTAL
-------- -------- -------- --------
(IN MILLIONS)
SIX MONTHS ENDED JUNE 30, 2001:
REVENUES
Oil sales $ 311 57 59 427
Gas sales 1,031 131 6 1,168
Natural gas liquids sales 55 9 -- 64
Marketing and midstream revenue 30 5 -- 35
-------- -------- -------- --------
Total revenues 1,427 202 65 1,694
-------- -------- -------- --------
PRODUCTION AND OPERATING COSTS AND EXPENSES
Lease operating expenses 168 32 18 218
Transportation costs 30 6 -- 36
Production taxes 73 1 -- 74
Marketing and midstream costs and expenses 25 3 28
Depreciation, depletion and amortization of property
and equipment 296 39 22 357
Amortization of goodwill 17 -- -- 17
General and administrative expenses 45 4 -- 49
Reduction of carrying value of oil and gas properties -- -- 77 77
-------- -------- -------- --------
Total production and operating costs and expenses 654 85 117 856
-------- -------- -------- --------
Earnings (loss) from operations 773 117 (52) 838
OTHER INCOME (EXPENSES)
Interest expense (65) (3) (1) (69)
Change in fair value of financial instruments (7) -- -- (7)
Other income 20 (2) 2 20
-------- -------- -------- --------
Net other income (expenses) (52) (5) 1 (56)
-------- -------- -------- --------
Earnings (loss) from continuing operations before income tax expense
(benefit) and cumulative effect of change in accounting principle 480 71 26 577721 112 (51) 782
INCOME TAX EXPENSE (BENEFIT)
Current 140132 1 3 1448 141
Deferred 44 30 8 82
---------- ---------- ---------- ----------141 45 (12) 174
-------- -------- -------- --------
Total income tax expense 184 31 11 226
---------- ---------- ---------- ----------(benefit) 273 46 (4) 315
-------- -------- -------- --------
Earnings (loss) from continuing operations before cumulative
effect of change in accounting principle 296 40448 66 (47) 467
DISCONTINUED OPERATIONS
Results of discontinued operations before income taxes -- -- 35 35
Total income tax expense -- -- 15 35115
-------- -------- -------- --------
Net results of discontinued operations -- -- 20 20
-------- -------- -------- --------
Earnings (loss) before cumulative effect of change in accounting principle 448 66 (27) 487
Cumulative effect of change in accounting principle 49 -- -- 49
---------- ---------- ---------- ------------------ -------- -------- --------
Net earnings 345 40 15 400(loss) 497 66 (27) 536
Preferred stock dividends 25 -- -- 2
---------- ---------- ---------- ----------5
-------- -------- -------- --------
Net earnings (loss) applicable to common shareholders $ 343 40 15 398
========== ========== ========== ==========492 66 (27) 531
======== ======== ======== ========
Capital expenditures, including acquisitions of businesses $ 231 61 54 346
========== ========== ========== ==========797 110 91 998
======== ======== ======== ========
1824
9.DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. 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
considerationin excess of
recorded accruals although actual amounts could differ from
management's estimate.accruals.
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
("CERCLA") and similar state statutes. In response to liabilities associated
with these activities, accruals have been established when reasonable estimates
are possible. Such accruals primarily include estimated costs associated with
remediation. Devon has not used discounting in determining its accrued
liabilities for environmental remediation, and no material claims for possible
recovery from third party insurers or other parties related to environmental
costs have been recognized in Devon's consolidated financial statements. Devon
adjusts the accruals when new remediation responsibilities are discovered and
probable costs become estimable, or when current remediation estimates must be
adjusted to reflect new information.
Certain of Devon's subsidiaries acquired in the 1999 merger with
PennzEnergy mergerCompany are involved in matters in which it has been alleged that
such subsidiaries are potentially responsible parties ("PRPs") under CERCLA or
similar state legislation with respect to various waste disposal areas owned or
operated by third parties. As of March 31,June 30, 2002, Devon's consolidated balance
sheet included $8$9 million of accrued liabilities, reflected in "Other
liabilities," forrelated to these and other environmental remediation.remediation liabilities.
Devon does not currently believe there is a reasonable possibility of incurring
additional material costs in excess of the current accruals recognized for such
environmental remediation activities. With respect to the sites in which Devon
subsidiaries are PRPs, Devon's conclusion is based in large part on (i) the
availability of defenses to liability, including the availability of the
"petroleum exclusion" under CERCLA and similar state laws, and/or (ii) Devon's
current belief that its share of wastes at a particular site is or will be
viewed by the Environmental Protection Agency or other PRPs as being de minimis.
As a result, Devon's monetary exposure is not expected to be material.
Royalty Matters
Numerous gas producers and related parties, including Devon, have been
named in various lawsuits filed by private litigants 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 natural gas liquids produced and
sold from federal and Indian owned or controlled lands. The various suits have
been consolidated 19
by the United States Judicial Panel on Multidistrict
Litigation for pre-trial proceedings in the matter of In re Natural Gas
Royalties Qui Tam Litigation, MDL-1293, United States District Court for the
District of Wyoming. Devon believes that it has acted reasonably, has legitimate
and strong defenses to all allegations in the suits, and has paid royalties in
good faith. Devon does not
25
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
currently believe that it is subject to material exposure in association with
these lawsuits and no liability has been recorded in connection therewith.
10. SUBSEQUENT EVENT - SALE OF INDONESIAN OPERATIONS
On April 19, 2002,Also, pending in federal court in Texas is a similar suit alleging
underpaid royalties to the United States in connection with natural gas and
natural gas liquids produced and sold from United States owned and/or controlled
lands. The claims were filed by private litigants against Devon completedand numerous
other producers, under the salefederal False Claims Act. The United States served
notice of all its operationsintent to intervene as to certain defendants, but not Devon. Devon
and certain other defendants are challenging the constitutionality of whether a
claim under the federal False Claims Act can be maintained absent government
intervention. Devon believes that it has acted reasonably and paid royalties in
Indonesia. The total sales price was $262 million, of which $12 milliongood faith. Devon does not currently believe that it is contingent upon successful completion of certain events.subject to material
exposure in association with this litigation. As of March 31, 2002,
the Indonesian operations were comprised of net property and equipment of $146
million, net working capital of $40 million and deferred income tax liabilities
of $44 million. The results of the Indonesian operations and any related gain on
sale willa result, Devon's monetary
exposure in this suit is not expected to be reported as discontinued operations in the three-month period ended
June 30, 2002.
20material.
26
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.OPERATIONS
The following discussion addresses material changes in results of
operations for the three monthsthree-month and six-month periods ended March 31,June 30, 2002,
compared to the three
monthsthree-month and six-month periods ended March 31,June 30, 2001, and in
financial condition since December 31, 2001. It is presumed that readers have
read or have access to Devon's 2001 Annual Report on Form 10-K which includes
disclosures regarding critical accounting policies as part of Management's
Discussion and Analysis of Financial Condition and Results of Operations.
OVERVIEW
Net earningsDevon recorded a net loss for the firstsecond quarter of 2002 were $62of $104
million, or $0.41$0.68 per share. This compares to net earnings of $400$136 million, or
$3.08$1.03 per share for the firstsecond quarter of 2001. Net loss for the first half of
2002 was $42 million, or $0.31 per share. This compares to net earnings for the
first half of 2001 of $536 million, or $4.11 per share. The decrease in second
quarter and first quarterhalf earnings was due to a decline in oil, natural gas and NGL
prices, increases in expenses and a $651 million reduction of carrying value of
Canadian oil and gas properties, the effects of which were partially offset by
an increase in production.
On January 24, 2002, Devon completed its acquisition of Mitchell.
Under the terms of this merger, Devon issued approximately 30 million shares of
Devon common stock and paid $1.6 billion in cash to the Mitchell stockholders.
The cash portion of the acquisition was funded from borrowings under a $3.0
billion senior unsecured term loan credit facility.
On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15,
2032. The net proceeds received, after discounts and issuance costs, were $986
million. The debt securities are unsecured and unsubordinated obligations of
Devon. The net proceeds from the issuance of these debt securities were partially used to pay down $820 million on theDevon's
$3 billion term loan credit facility. The remaining $166 million of net proceeds
net of discounts and issuance costs, will bewas used in June 2002 to partially fund the early extinguishment of $175 million
of 8.75% senior notes due June 15, 2007. The notes are redeemable by Devon on June 15, 2002,were redeemed at 104.375% of
principal, or approximately $183 million.
21On June 7, 2002, Devon renewed the $800 million, 364-day portion of its
unsecured long-term credit facilities (the "Credit Facilities"). The Credit
Facilities include a U.S. facility of $725 million (the "U.S. Facility") and a
Canadian facility of $275 million (the "Canadian Facility").
On July 25, 2002, Devon renewed and increased its letter of credit and
revolving bank facility ("LOC Facility") for its Canadian operations. This C$150
million LOC Facility will be used primarily by Devon's wholly-owned
subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to
issue letters of credit. As of July 31, 2002, C$104 million of letters of credit
were issued under the LOC Facility primarily for Canadian drilling commitments.
27
RESULTS OF OPERATIONS
Total revenues decreased $93increased $466 million, or 9%67%, in the second quarter of
2002, and $387 million, or 23%, in the first quarterhalf of 2002. This was the result
of decreasesincreases in oil, gas and NGL production and an increase in marketing and
midstream revenue, partially offset by a decline in the average prices of oil,
gas and NGLs, partially offset by higherNGLs. The increases in production on a combined Boe basis and an
increase in marketing and midstream revenue.revenue
were primarily the result of the Anderson and Mitchell acquisitions.
Oil, gas and NGL revenues decreased
$233were up $214 million, or 23%31%, for the firstsecond
quarter of 2002 compared to the second quarter of 2001, and were down $5 million
for the first quarterhalf of 2002 compared to the first half of 2001. The quarterly comparisonsthree-month
and six-month periods comparison of production and price changes are shown in
the following tables. (Note: Unless otherwise stated, all dollar amounts are
expressed in U.S. dollars.)
TOTAL
----------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED MARCH 31,
---------------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------------- -----------------------------------
2002 2001 CHANGE --------- --------- ---------2002 2001 CHANGE
-------- -------- -------- -------- -------- --------
PRODUCTION
Oil (MMBbls) 14 10 +40%11 9 +22% 24 18 +33%
Gas (Bcf) 195 122 +74%199 108 +84% 394 220 +79%
NGLs (MMBbls) 4 1 +300%6 2 +200% 10 3 +233%
Oil, Gas and NGLs (MMBoe)(1) 51 30 +70%50 29 +72% 100 58 +72%
AVERAGE PRICES
Oil (Per Bbl) $ 18.69 24.33 -23%22.41 23.08 -3% 20.41 23.63 -14%
Gas (Per Mcf) 2.41 6.49 -63%2.83 4.09 -31% 2.62 5.30 -51%
NGLs (Per Bbl) 12.24 24.55 -50%13.61 19.63 -31% 12.97 21.84 -41%
Oil, Gas and NGLs (Per Boe)(1) 15.38 33.29 -54%
(IN17.87 23.78 -25% 16.58 28.75 -42%
($'S IN MILLIONS)
REVENUES
Oil $ 254 254 --262 209 +25% 495 427 +16%
Gas 468 725 -35%564 443 +27% 1,032 1,168 -12%
NGLs 5672 32 +75%
--------- ---------+125% 127 64 +98%
-------- -------- -------- --------
Combined $ 778 1,011 -23%
========= =========898 684 +31% 1,654 1,659 --
======== ======== ======== ========
2228
DOMESTIC
-------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED MARCH 31,
------------------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------------- ----------------------------------
2002 2001 CHANGE ---------- ---------- ----------2002 2001 CHANGE
-------- -------- -------- -------- -------- --------
PRODUCTION
Oil (MMBbls) 7 7 --6 6 +0% 13 13 +0%
Gas (Bcf) 120 95 +26%127 90 +41% 247 185 +34%
NGLs (MMBbls) 4 2 +100% 7 3 1 +200%+133%
Oil, Gas and NGLs (MMBoe)(1) 30 24 +25%31 23 +35% 61 47 +30%
AVERAGE PRICES
Oil (Per Bbl) $ 19.31 24.85 -22%22.32 23.02 -3% 20.81 23.97 -13%
Gas (Per Mcf) 2.52 6.80 -63%2.97 4.27 -30% 2.75 5.56 -50%
NGLs (Per Bbl) 12.01 23.81 -50%12.91 18.82 -31% 12.52 21.01 -40%
Oil, Gas and NGLs (Per Boe)(1) 15.77 35.43 -55%
(IN18.16 24.48 -26% 17.01 30.05 -43%
($'S IN MILLIONS)
REVENUES
Oil $ 130 166 -22%148 144 +3% 278 311 -11%
Gas 303 643 -53%377 388 -3% 680 1,031 -34%
NGLs 35 27 +30%
---------- ----------51 28 +82% 86 55 +56%
-------- -------- -------- --------
Combined $ 468 836 -44%
========== ==========576 560 +3% 1,044 1,397 -25%
======== ======== ======== ========
CANADA
-------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED MARCH 31,
------------------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------------- ----------------------------------
2002 2001 CHANGE ---------- ---------- ----------2002 2001 CHANGE
-------- -------- -------- -------- -------- --------
PRODUCTION
Oil (MMBbls) 5 1 +400%4 2 +100% 9 3 +200%
Gas (Bcf) 73 15 +387%71 16 +344% 144 31 +365%
NGLs (MMBbls)(1) 2 -- N/M 3 -- N/M
Oil, Gas and NGLs (MMBoe)(1) 18 45 +260% 36 8 +350%
AVERAGE PRICES
Oil (Per Bbl) $ 17.44 21.61 -19%22.51 21.72 +4% 19.77 21.67 -9%
Gas (Per Mcf) 2.23 5.23 -57%2.60 3.36 -23% 2.41 4.28 -44%
NGLs (Per Bbl) 12.61 29.45 -57%15.72 27.25 -42% 14.03 28.42 -51%
Oil, Gas and NGLs (Per Boe)(1) 14.36 28.15 -49%
(IN17.21 20.93 -18% 15.74 24.50 -36%
($'S IN MILLIONS)
REVENUES
Oil $ 82 28 +193%90 29 +210% 172 57 +202%
Gas 163 79 +106%185 52 +256% 348 131 +166%
NGLs 20 5 +300%
---------- ----------21 4 +425% 41 9 +356%
-------- -------- -------- --------
Combined $ 265 112 +137%
========== ==========296 85 +248% 561 197 +185%
======== ======== ======== ========
2329
INTERNATIONAL
-------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED MARCH 31,
------------------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------------- ----------------------------------
2002 2001 CHANGE ---------- ---------- ----------2002 2001 CHANGE
-------- -------- -------- -------- -------- --------
PRODUCTION
Oil (MMBbls) 1 1 +0% 2 2 --+0%
Gas (Bcf) 1 2 2 ---50% 3 4 -25%
NGLs (MMBbls) -- -- N/M -- -- N/M
Oil, Gas and NGLs (MMBoe)(1) 2 2 --1 1 +0% 3 3 +0%
AVERAGE PRICES
Oil (Per Bbl) $ 19.48 24.34 -20%22.55 24.64 -8% 20.55 23.95 -14%
Gas (Per Mcf) 1.32 1.31 +1%1.41 1.45 -3% 1.37 1.39 -1%
NGLs (Per Bbl) 14.49 25.00 -42%-- -- N/M -- -- N/M
Oil, Gas and NGLs (Per Boe)(1) 18.16 22.43 -19%
(IN19.54 21.34 -8% 18.08 20.53 -12%
($'S IN MILLIONS)
REVENUES
Oil $ 42 60 -29%24 36 -33% 45 59 -24%
Gas 2 3 -33% 4 6 -33%
NGLs 1-- -- N/M ---------- ------------ -- N/M
-------- -------- -------- --------
Combined $ 45 63 -27%
========== ==========26 39 -33% 49 65 -25%
======== ======== ======== ========
- ----------
(1) Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per
barrel of oil, based upon the approximate relative energy content of
natural gas and oil, which rate is not necessarily indicative of the
relationship of oil and gas prices. The respective prices of oil, gas and
NGLsNGL are affected by market and other factors in addition to relative energy
content.
N/M Not meaningful.
The average sales prices per unit of production shown in the preceding
tables include the effect of Devon's hedging activities. Following is a
comparison of Devon's average sales prices with and without the effect of hedges
for the three-month and six-month periods ended March 31,June 30, 2002 and 2001.
WITH HEDGES WITHOUT HEDGES
----------------------- -------------------------------------------- ---------------------
THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, MARCH 31,
----------------------- -----------------------JUNE 30, JUNE 30,
2002 2001 2002 2001
---------- ---------- ---------- ------------------ -------- -------- --------
Oil (per Bbl) $ 18.69 24.3322.41 23.08 $ 18.27 25.0723.45 23.80
Gas (per Mcf) $ 2.41 6.492.83 4.09 $ 2.12 6.562.86 4.26
NGLs (per Bbl) $ 12.24 24.5513.61 19.63 $ 12.24 24.5513.61 19.63
Oil, Gas and NGLs (per Boe) $ 15.38 33.2917.87 23.78 $ 14.18 33.9918.18 24.67
WITH HEDGES WITHOUT HEDGES
--------------------- ---------------------
SIX MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2002 2001 2002 2001
-------- -------- -------- --------
Oil (per Bbl) $ 20.41 23.63 $ 20.67 24.41
Gas (per Mcf) $ 2.62 5.30 $ 2.50 5.45
NGLs (per Bbl) $ 12.97 21.84 $ 12.97 21.84
Oil, Gas and NGLs (per Boe) $ 16.58 28.75 $ 16.15 29.64
30
OIL REVENUES. Oil revenues were essentially flatincreased $53 million, or 25%, in the firstsecond
quarter of 2002. Oil revenues decreased $76 million due to a $5.64 per barrel decrease
in the average price of oil in 2002. An increase in 2002's production of 42 million barrels caused
oil revenues to increase by 24
$76$61 million. The October 2001 Anderson acquisition
and the January 2002 Mitchell acquisition accounted for substantially all of the
increased production. The effects of the production increase were partially
offset by a $0.67 per barrel decrease in the average price of oil in 2002.
Oil revenues increased $68 million, or 16%, in the first half of 2002.
An increase in production of 6 million barrels, or 33%, caused oil revenues to
increase by $146 million. The Anderson and Mitchell acquisitions were primarily
responsible for the increased production. The effects of the production increase
were partially offset by a $3.22 per barrel decrease in the average price of oil
in 2002.
GAS REVENUES. Gas revenues increased $121 million, or 27%, in the
second quarter of 2002. An increase in production of 91 Bcf, or 84%, caused gas
revenues to increase by $372 million. The Anderson and Mitchell acquisitions
were primarily responsible for the increased production. The effects of the
production increase were partially offset by a $1.26 per Mcf decrease in the
average gas price in the second quarter of 2002.
Gas revenues decreased $257$136 million, or 12%, in 2002'sthe first quarter. Of this total decrease, $795 million was due to a $4.08half of 2002.
A $2.68 per Mcf decrease in the average gas price in the first quarterhalf of 2002. This was2002
caused revenues to decrease $592 million. The effects of the price decline were
partially offset by a $538 million increase related to a production increase of 73174 Bcf in the 2002 period. The
Anderson and Mitchell acquisitions accounted for substantially all of the
increased production.
NGL REVENUES. NGL revenues increased $24$40 million in the firstsecond quarter
of 2002. Of this total increase, $80 million was due to a 3A 4 million barrel increase in 2002 production.production caused revenues to
increase $72 million. The Anderson and Mitchell acquisitions accounted for
substantially all of the increase. This wasincreased production. The effects of the production
increase were partially offset by a $56$6.02 per barrel decrease in the average NGL
price in the second quarter of 2002.
NGL revenues increased $63 million decrease
relatedin the first half of 2002. A 7
million barrel increase in 2002 production caused revenues to a $12.31increase $149
million. The Anderson and Mitchell acquisitions were primarily responsible for
the increased production. The effects of the production increase were partially
offset by an $8.87 per barrel decrease in the average NGL price in the first
quarterhalf of 2002.
MARKETING AND MIDSTREAM REVENUES. Marketing and midstream revenues
increased $140$252 million or 692%,and $392 million in the second quarter and first quarterhalf of
2002.2002, respectively. The Mitchell acquisition included significant marketing and
midstream assets which accountsaccounted for the increase in revenues.
31
PRODUCTION AND OPERATING EXPENSES. The components of production and
operating expenses for the first quarter of 2002 and 2001 are set forth in the following tables.
TOTAL
-------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED MARCH 31,
------------------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------------- ----------------------------------
2002 2001 CHANGE ---------- ---------- ----------2002 2001 CHANGE
-------- -------- -------- -------- -------- --------
($'S IN MILLIONS)
ABSOLUTE
(Millions)
Recurring leaseLease operating expenses $ 161 116 +39%
Well workover expenses 9 7 +29%166 107 +55% 325 218 +49%
Transportation costs 38 17 +124%19 +100% 76 36 +111%
Production taxes 22 45 -51%
---------- ----------35 29 +21% 57 74 -23%
-------- -------- -------- --------
Total production and operating expenses $ 230 185 +24%
========== ==========239 155 +54% 458 328 +40%
======== ======== ======== ========
PER BOE
Recurring leaseLease operating expenses 3.20 3.82 -16%
Well workover expenses 0.16 0.21 -24%3.30 3.74 -12% 3.26 3.78 -14%
Transportation costs 0.75 0.57 +32%0.64 +16% 0.75 0.62 +21%
Production taxes 0.44 1.47 -70%
---------- ----------0.70 1.03 -32% 0.58 1.28 -55%
-------- -------- -------- --------
Total production and operating expenses $ 4.55 6.07 -25%
========== ==========4.75 5.41 -12% 4.59 5.68 -19%
======== ======== ======== ========
Recurring leaseLease operating expenses increased $45$59 million and $107 million in the
second quarter and first quarterhalf of 2002.2002, respectively. The Anderson and Mitchell
acquisitions accounted for $58$62 million and $123 million of the increase.increases,
respectively. The historical
25
Devon lease operating expenses decreased $13$3 million
and $16 million, respectively, due to lower fuel and electricity costs as well
as lower third-party field service costs.
Transportation costs increased $21$19 million and $40 million in the
second quarter and first half of 2002, respectively, primarily due to an
increase in gas production from the Anderson and Mitchell acquisitions and
increases in transportation costs.costs per unit.
Production taxes increased $6 million in second quarter of 2002 and
decreased $23$17 million in the 2002 quarter.first half of 2002. The majority of Devon's
production taxes are assessed on its onshore domestic properties. In the U.S.,
most of the production taxes are based on a fixed percentage of revenues.
Therefore, the 44%3% increase and 25% decrease in domestic oil, gas and NGL
revenues in the second quarter and first quarterhalf of 2002, wasrespectively, were the
primary causecauses of the production tax decrease.change.
MARKETING AND MIDSTREAM COSTS AND EXPENSES. Marketing and midstream
costs and expenses increased $109$210 million or 681%,and $319 million in the second quarter
and first quarterhalf of 2002.2002, respectively. The Mitchell acquisition included
significant marketing and midstream assets which accountsaccounted for the increase in
costs and expenses.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSES ("DD&A"). Oil and gas
property related DD&A increased $124$131 million, or 71%78%, from $174$169 million in the
firstsecond quarter of 2001 to $298$300 million in the firstsecond quarter of 2002. Oil and
gas property related DD&A expense increased $116$127 million due to the 70%72% increase
in combined oil, gas and NGLs production in 2002. Additionally, an increase in
the combined U.S., Canadian and international DD&A rate from $5.73$5.89 per Boe in
2001 to $5.88$5.97 per Boe in 2002 caused oil and gas property related DD&A to
increase by $8$4 million.
32
Oil and gas property related DD&A increased $257 million, or 76%, from
$337 million in the first half of 2001 to $594 million in the first half of
2002. Oil and gas property related DD&A expense increased $246 million due to
the 72% increase in combined oil, gas and NGLs production in 2002. Additionally,
an increase in the combined U.S., Canadian and international DD&A rate from
$5.84 per Boe in 2001 to $5.95 per Boe in 2002 caused oil and gas property
related DD&A to increase by $11 million.
Non-oil and gas property DD&A expense increased $13$16 million from $9$11
million in the firstsecond quarter of 2001 compared to $22$27 million the second quarter
of 2002. Non-oil and gas property DD&A expense increased $29 million from $20
million in the first half of 2001 compared to $49 million the first quarterhalf of
2002. Depreciation of the marketing and midstream assets acquired in the January
2002 Mitchell acquisitions accounted for the increase.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A"). Devon's net G&A consists
of three primary components. The largest of these components is the gross amount
of expenses incurred for personnel costs, office expenses, professional fees and
other G&A items. The gross amount of these expenses is partially reduced by two
offsetting components. One is the amount of G&A capitalized pursuant to the
full-cost method of accounting. The other is the amount of G&A reimbursed by
working interest owners of properties for which Devon serves as the operator.
These reimbursements are received during both the drilling and operational
stages of a property's life. The gross amount of G&A incurred, less the amounts
capitalized and reimbursed, is recorded as net G&A in the consolidated
statements of operations. The following table is a summary of G&A expenses by
component for the second quarter and first quarterhalf of 2002 and 2001.
26
THREE MONTHS ENDED MARCH 31,
-------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
2002 2001 ---------- ----------2002 2001
-------- -------- -------- --------
(IN MILLIONS)
Gross G&A $ 91 5199 61 190 112
Capitalized G&A (22) (16)(27) (23) (49) (39)
Reimbursed G&A (20) (13)
---------- ----------(18) (12) (37) (24)
-------- -------- -------- --------
Net G&A $ 54 26 104 49
22
========== ================== ======== ======== ========
Net G&A increased $27$28 million and $55 million, or 123%108% and 112%, in the
second quarter and first quarterhalf of 2002 compared to the first quartersame periods of 2001.2001,
respectively. Gross G&A increased $40$38 million and $78 million, or 78%.62% and 70%,
in the second quarter and first half of 2002 compared to the same periods of
2001, respectively. The increase in gross expenses in the first quarterboth periods of 2002 was
primarily related to the Anderson and Mitchell acquisitions.
Capitalized G&A was reducedincreased $4 million and $10 million in the second
quarter and first half of 2002, respectively. Reimbursed G&A increased $6
million due to an increaseand $13 million in the amount capitalized
as partsecond quarter and first half of oil and gas properties. G&A was also reduced $7 million due to an
increase in the amount of reimbursements on operated properties in the 2002,
quarter.respectively. Changes in both of the capitalized and reimbursed amounts were
primarily related to the Anderson and Mitchell acquisitions.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES. Under the full
cost method of accounting, the net book value of oil and gas properties less
related deferred income taxes (the "costs
33
to be recovered"), may not exceed a calculated "full cost ceiling." The ceiling
limitation is the discounted estimated after-tax future net revenues from oil
and gas properties. The ceiling is imposed separately by country. In calculating
future net revenues, current prices and costs are generally held constant
indefinitely, and Devon does not include the effect of hedges in the calculation
of the future net revenues. Therefore, the ceiling limitation is not necessarily
indicative of the properties' fair value. The costs to be recovered are compared
to the ceiling on a quarterly basis. If the costs to be recovered exceed the
ceiling, the excess is written off as an expense, except as discussed in the
following paragraph.
If, subsequent to the end of the quarter but prior to the applicable
financial statements being published, prices increase to levels such that the
ceiling would exceed the costs to be recovered, a writedown otherwise indicated
at the end of the quarter is not required to be recorded. A writedown indicated
at the end of a quarter is also not required if the value of additional reserves
proved up on properties after the end of the quarter but prior to the publishing
of the financial statements would result in the ceiling exceeding the costs to
be recovered, as long as the properties were owned at the end of the quarter.
An expense recorded in one period may not be reversed in a subsequent
period even though higher oil and gas prices may have increased the ceiling
applicable to the subsequent period.
Based on oil and natural gas cash market prices as of June 30, 2002,
Devon's Canadian costs to be recovered exceeded the related ceiling value by
$371 million. This after-tax amount resulted in a pre-tax reduction of the
carrying value of Devon's Canadian oil and gas properties of $651 million in the
second quarter of 2002. This reduction was the result of a sharp drop in
Canadian gas prices during the last half of June 2002. The June 30, 2002
reference prices used in the Canadian ceiling calculation, expressed in Canadian
dollars, were a NYMEX price of C$40.79 per barrel of oil and an AECO price of
C$2.17 per Mcf. The cash market prices of natural gas increased during the month
of July 2002 prior to Devon's release of its second quarter results, but the
increase was not sufficient to offset the entire reduction calculated as of June
30, 2002.
Under the purchase method of accounting for business combinations,
acquired oil and gas properties are recorded at fair value as of the date of
purchase. Devon estimates such fair value using its estimates of future oil and
gas prices. In contrast, the ceiling calculation dictates that prices in effect
as of the last day of the applicable quarter are held constant indefinitely.
Accordingly, the resulting value is not necessarily indicative of the fair value
of the reserves. The oil and gas properties added from the Anderson acquisition
in 2001 were recorded at fair values that were based on expected future oil and
gas prices higher than the June 30, 2002, prices used to calculate the ceiling.
During the second quarter of 2001, Devon elected to discontinue
operations in Malaysia, Qatar and on certain properties in Brazil. Accordingly,
during the second quarter of 2001, Devon recorded a $77 million charge
associated with the impairment of these properties. The after-tax effect of this
reduction was $62 million.
INTEREST EXPENSE. Interest expense increased $90$113 million and $203
million, or 254%323% and 294%, in 2002'sthe second quarter and first quarter. Anhalf of 2002,
respectively, due to an increase in the average debt balance outstandingoutstanding. The
average debt balance increased from $1.9 billion in second quarter
34
of 2001 to $8.3$8.9 billion in the 2002 caused interest expensequarter. The average debt balance increased
from $1.9 billion in the first half of 2001 to increase
by $90 million.$8.6 billion in the first half of
2002. The increase in the average debt balance in the 2002 periods caused
interest expense to increase $106 million and $196 million in the second quarter
and first quarterhalf of 2002, respectively. This increase was primarily attributable
to the long-term debt issued to complete the Anderson and Mitchell acquisitions.
The average interest rate on outstanding debt decreased from 6.8% in
the 2001 quarter to 5.8%6.0% in the 2002 quarter and from 6.8% in the first half of
2001 to 5.9% in the first half of 2002 due to the favorable rates on the
borrowings under the $3 billion term loan credit facility. This facility's rates
averaged less than 3% during the 2002 quarter.periods. The overall rate decrease caused
interest expense to decrease $5$3 million and $8 million in the second quarter and
first half of 2002, period.respectively. Other items included in interest expense that
are not related to the debt balance outstanding were $5$10 million and $15 million
higher in the second quarter and first half of 2002, quarter comparedrespectively. Of this
increase, $8 million related to the 2001 quarter. These itemsearly extinguishment of 8.75% senior notes.
Items not related to the balance of debt outstanding include facility and agency
fees, amortization of costs and other miscellaneous items.
The following schedule includes the components of interest expense for
the second quarter and first half of 2002 and 2001.
THREE MONTHS ENDED MARCH 31,
------------------------SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
2002 2001 ---------- ----------2002 2001
-------- -------- -------- --------
(IN MILLIONS)
Interest based on debt outstanding $ 118 33134 31 252 64
Amortization of discounts and premiums, net 3 2 6 4
Facility and agency fees -- -- 1 --
Amortization of capitalized loan costs 2 1 --3 1
Capitalized interest (1) -- (2) (1)
Loss on early debt retirement 8 -- 8 --
Other 2 --
---------- ----------1 4 1
-------- -------- -------- --------
Total interest expense $ 124 34
========== ==========148 35 272 69
======== ======== ======== ========
27
EFFECTS OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATES. The devaluation
of the Argentine peso resulted in a $3 million and $6 million loss in the second
quarter and first half 2002, period.respectively. Additionally, as a result of the
Anderson acquisition, Devon's Canadian subsidiary assumed certainhas $400 million of fixed-rate
senior notes which are denominated in U.S. dollars. Changes in the exchange rate
between the U.S. dollar and the Canadian dollar from the dates the notes were
acquired to the dates of repayment increase or decrease the expected amount of
Canadian dollars eventually required to repay the notes. Such changes in the
Canadian dollar equivalent balance of the debt are required to be included in
determining net earnings for the period in which the exchange rate changes. The
dropincrease in the Canadian-to-U.S. dollar exchange rate from $0.628$0.6275 at March 31,
2002 to $0.6585 at June 30, 2002 resulted in a $19 million gain in the second
quarter of 2002. The increase in the Canadian-to-U.S. dollar exchange rate from
$0.6279 at December 31, 2001 to $0.6275$0.6585 at March 31, 2001June 30, 2002 resulted in a $1an $18
million loss.gain in the first half of 2002.
35
INCOME TAXES. During interim periods, income tax expense is based on
the estimated effective income tax rate that is expected for the entire fiscal
year. The estimated effective tax rate in the firstsecond quarter of 2002 was 26%,a
benefit of 53% compared to 39% estimatedan expense of 43% in the firstsecond quarter of 2001. The
lower expectedestimated effective tax rate was a benefit of 59% in the first half of 2002
compared to an expense of 40% in the first half of 2001. Excluding the effect of
the reduction of carrying value of Canadian oil and gas properties, the
effective tax rate was 24% and 25% in the second quarter and first half of 2002,
respectively.
The 2002 rate, isexcluding the Canadian writedown, was lower than the
statutory federal tax rate primarily due to the tax benefits of certain foreign
deductions. The 2001 rate was higher than the statutory federal tax rate due to
the effect of state taxes, goodwill amortization that was not deductible for
income tax purposes and the effect of foreign income taxes.
Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes ("SFAS No. 109"), requires that the tax benefit of available tax
carryforwards be recorded as an asset to the extent that management assesses the
utilization of such carryforwards to be "more likely than not". When the future
utilization of some portion of the carryforwards is determined not to be "more
likely than not", SFAS No. 109 requires that a valuation allowance be provided
to reduce the recorded tax benefits from such assets.
Included as deferred tax assets at March 31,June 30, 2002, were approximately
$157 million of tax related carryforwards. The carryforwards include U.S.
federal net operating loss carryforwards, the majority of which do not begin to
expire until 2008, U.S. state net operating loss carryforwards which expire
primarily between 2002 and 2014, Canadian carryforwards which expire primarily
between 2002 and 2008 and minimum tax credits which have no expiration. Devon
expects the tax benefits from the net operating loss carryforwards to be
utilized between 2002 and 2010. Such expectation is based upon current estimates
of taxable income during this period, considering limitations on the annual
utilization of these benefits as set forth by federal tax regulations.
Significant changes in such estimates caused by variables such as future oil and
gas 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, Devon's
management believes that future taxable income will more likely than not be
sufficient to utilize substantially all its tax carryforwards prior to their
expirations.
28
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE. At the time of
adoption ofOn January 1,
2001, Devon adopted SFAS No. 133, Accounting for Derivative Instruments and
Certain Hedging Activities,Activities. Upon adoption, Devon recorded a net-of-tax
cumulative-effect-type adjustment to net earnings of $49 million gain related to
the fair value of derivatives that do not qualify as hedges. This gain included
$46 million related to the option embedded in the debentures that are
exchangeable into shares of ChevronTexaco Corporation common stock.
CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY
The following discussion of capital expenditures, capital resources and
liquidity should be read in conjunction with the consolidated statements of cash
flows included in Part 1, Item 1.
36
CAPITAL EXPENDITURES. Approximately $2.2$2.6 billion was spent in the first
threesix months of 2002 for capital expenditures. This total includes $1.7 billion
related to the January 2002 Mitchell acquisition and $0.5$0.8 billion for the
acquisition, drilling or development of oil and gas properties. These amounts
compare to first quarterhalf 2001 capital expenditures of $346 million$1.0 billion ($332 million1.0 billion of
which was related to oil and gas properties).
OTHER CASH USES. Devon's common stock dividends were $8$16 million and
$7$13 million in the first quarterhalf of 2002 and 2001, respectively. Devon also paid $2$5
million of preferred stock dividends in each of the first quarterssix months of 2002 and
2001.
CAPITAL RESOURCES AND LIQUIDITY. Devon's primary source of liquidity
has historically been net cash provided by operating activities ("operating cash
flow"). This source has been supplemented as needed by accessing credit lines
and commercial paper markets and issuing equity securities and long-term debt
securities. In 2002, another major source of liquidity will behas been sales of oil and
gas properties.
Net cash provided by operating activities ("operating cash flow")
continued to be thea primary source of capital and liquidity in the first quarterhalf of
2002. Operating cash flow in the first quarterhalf of 2002 was $372$896 million, compared
to $757 million$1.1 billion in the first quarterhalf of 2001. The decrease in operating cash flow
in the first half of 2002 quarter was primarily caused by the decline in revenuescommodity
prices and increased expenses, as discussed earlier in this section.
Devon's operating cash flow is sensitive to many variables, the most
volatile of which is pricing of the oil, natural gas and NGLs produced. Prices
for these commodities are determined primarily by prevailing market conditions.
Regional and worldwide economic conditions, weather and other substantially
variable factors influence market conditions for these products. These factors
are beyond Devon's control and are difficult to predict.
To mitigate some of the risk inherent in oil and natural gas prices,
Devon has entered into various fixed-price physical delivery contracts and
financial price swap contracts to fix the price to be received for a portion of
future oil and natural gas production. Additionally, Devon has 29
utilized price
collars to set minimum and maximum prices on a portion of its production. The
table below provides the volumes associated with these various arrangements as
of April 30,July 31, 2002.
Fixed-Price Physical Price Swap Price
Delivery Contracts Contracts Collars Total
-------------------- ---------- ------- -----
Oil production (MMBbls)
2002 2 10 10 227 19
2003 -- -- 6 69 9
Natural gas production (Bcf)
2002 59 111 177 34757 118 174 349
2003 2916 37 145 181195 248
2004 2616 -- -- 2618 34
For the years 2005 through 2011, Devon has fixed-price physical delivery
contracts covering Canadian natural gas production ranging from 1310 Bcf to 1914 Bcf
per year. Thereafter, Devon also has Canadian gas volumes subject to fixed-price
contracts in the years from 2012 through 2016, but the yearly volumes are less
than 1 Bcf.
37
By removing the price volatility from the above volumes of oil and
natural gas production, Devon has mitigated, but not eliminated, the potential
negative effect of declining prices on its operating cash flow.
Other sources of liquidity are Devon's revolving lines of credit. AsOn
June 7, 2002, Devon renewed the $800 million, 364-day portion of March 31, 2002, theseits unsecured
long-term credit lines totaled $1 billion, of which $831 million was
available to Devon for future borrowings.facilities (the "Credit Facilities"). The majority of the revolving credit
lines consist ofCredit Facilities
include a U.S. facility of $725 million (the "U.S. Facility") and a Canadian
facility of $275 million (the "Canadian Facility").
Amounts borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon had $13may elect for periods up to six months. Such rates
are generally less than the prime rate. Devon may also elect to borrow at the
prime rate. The Credit Facilities provide for an annual facility fee of $1.4
million that is payable quarterly.
The $725 million U.S. Facility consists of a Tranche A facility of $200
million and a Tranche B facility of $525 million. The Tranche A facility matures
on October 15, 2004. Devon may borrow funds under the Tranche B facility until
June 5, 2003 (the "Tranche B Revolving Period"). Devon may request that the
Tranche B Revolving Period be extended an additional 364 days by notifying the
agent bank of such request between 30 and 60 days prior to the end of the
Tranche B Revolving Period. On June 6, 2003, at the end of the Tranche B
Revolving Period, Devon may convert the then outstanding balance under the
Tranche B facility to a two-year term loan by paying the Agent a fee of 12.5
basis points. The applicable borrowing rate would be at LIBOR plus 125 basis
points. On June 30, 2002, there were no borrowings outstanding under the $725
million U.S. Facility. The available capacity under the U.S. Facility, net of
commercial paper borrowings as of June 30, 2002, was $410 million.
Devon may borrow funds under the $275 million Canadian Facility until
June 5, 2003 (the "Canadian Facility Revolving Period"). Devon may request that
the Canadian Facility Revolving Period be extended an additional 364 days by
notifying the agent bank of such request between 30 and 60 days prior to the end
of the Canadian Facility Revolving Period. Debt outstanding as of the end of the
Canadian Facility Revolving Period is payable in semiannual installments of 2.5%
each for the following five years, with the final installment due five years and
one day following the end of the Canadian Facility Revolving Period. On June 30,
2002, there were no borrowings under the $275 million Canadian facility.
Under the terms of the Credit Facilities, Devon has the right to
reallocate up to $100 million of borrowings underthe unused Tranche B facility maximum credit
amount to the Canadian Facility. Conversely, Devon also has the right to
reallocate up to $100 million of unused Canadian Facility maximum credit amount
to the Tranche B Facility.
On July 25, 2002, Devon renewed and increased its letter of credit and
revolving credit facilities at Marchbank facility ("LOC Facility") for its Canadian operations. This C$150
million LOC Facility will be used primarily by Devon's wholly-owned
subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to
issue letters of credit. As of July 31, 2002, at an interest rateC$104 million of 3.8%.letters of credit
were issued under the LOC Facility primarily for Canadian drilling commitments.
Devon also has access to short-term credit under its commercial paper
program. Total borrowings under the U.S. Facility and the commercial paper
program may not exceed $725
38
million. Commercial paper debt generally has a maturity of between seven to 90
days, although it can have a maturity of up to 365 days. Devon had $156$315 million
of commercial paper debt outstanding at March
31,June 30, 2002, at an interest rate of
2.6%2.3%.
A portion of cash used in the Anderson and Mitchell acquisitions was
provided by a $3 billion senior unsecured credit facility. This credit facility,
which was entered into in October 2001, has a term of five years. The $3 billion
credit facility was fully borrowed upon the closing of the Mitchell acquisition
on January 24, 2002. However, as of March 31,June 30, 2002, borrowings under this
facility have been reduced by $900 million. Debt under this facility$1.7 billion of the balance
outstanding was reduced
by an additional $445 million from April 1, 2002 through May 3, 2002. Of this
total reduction, $820 million came fromretired. The primary sources of the repayments were the issuance
of $1 billion of debt securities discussed below and $525$896 million came from 30
the sale
of certain oil and gas properties. With the proceeds from additional property
sales.sales through July 31, 2002, the term loan balance has been further reduced by
$153 million. The term loan's balance as of July 31, 2002, was $1.1 billion.
The remaining balance outstanding as of May 3,July 31, 2002 will mature as
follows:
(In Millions)
-------------
October 15, 2005 $ 87
April 15, 2006 $ 800335
October 15, 2006 $ 800
--------------------
$ 1,687
=======1,135
=============
This $3 billion facility includes various rate options which can be
elected by Devon, including a rate based on LIBOR plus a margin. Through June
17, 2002, this margin iswas fixed at 100 basis points. Thereafter, the margin will
beis
based on Devon's debt rating. Based on Devon's current debt rating, the margin
after June 17, 2002, would beis 100 basis points. As of May 3,August 1, 2002, Devon
had $1.7 billion borrowed under this facility at anthe average
interest rate of
2.9%on this facility was 2.8%.
Devon's $1 billion revolving credit facilities and its $3 billion term
loan credit facility each contain only one material financial covenant. This
covenant requires Devon to maintain a ratio of total funded debt to total
capitalization of no more than 70% through June 30, 2002, and no more than 65%
thereafter. The credit agreements contain definitions of total funded debt and
total capitalization that include adjustments to the respective amounts reported
in Devon's consolidated financial statements. Per the agreements, total funded
debt excludes the debentures that are exchangeable into shares of ChevronTexaco
Corporation common stock. Also, total capitalization is adjusted to add back
noncash financial writedowns such as full cost ceiling property impairments or
goodwill impairments. As of March 31,June 30, 2002, Devon's ratio of total funded debt to
total capitalization, as defined in its credit agreements, was 60.8%56.1%.
On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15,
2032. The net proceeds received, after discounts and issuance costs, were $986
million. The debt securities are unsecured and unsubordinated obligations of
Devon. The net proceeds from the issuance of these debt securities were partially used to pay down $820 million on theDevon's
$3 billion term loan credit facility. The remaining $166 million of net proceeds
net of discounts and issuance costs, will bewas used in June 2002 to partially fund the early extinguishment of $175 million
of 8.75% senior notes due June 15, 2007. The notes are redeemable by Devon on June 15, 2002,were redeemed at 104.375% of
principal, or approximately $183 million.
During 2002, Devon estimates that it will sell certain oil and gas
properties (the "Disposition Properties") for between $1.2$1.3 billion and $1.5$1.6
billion. The Disposition Properties
39
are predominantly those that are either outside of Devon's core operating areas
or otherwise do not fit Devon's current strategic objectives. The Disposition
Properties are located in the U.S., Canada and International areas.
As of May 3,July 31, 2002, Devon has closed sales of Disposition Properties
totaling $604 million$1.3 billion in proceeds, and has signed agreements for an additional
$598 million of transactions which are expected to close by the end of the
second quarter of 2002.proceeds. In addition, Devon has
31
identified another
$200 million to $300 million of Disposition Properties that could be sold in the
second half of the year.
A summary of Devon's contractual obligations as of March 31,June 30, 2002, is
provided in the following table.
PAYMENTS DUE BY YEAR
---------------------------------------------------------------------------------------------------------------------------------------------------
AFTER
2002 2003 2004 2005 2006 2006 TOTAL
-------- -------- -------- -------- -------- -------- -------------- ------ ------ ------ ------ ------ -------
(IN MILLIONS)
Long-term debt $ -- -- 493 883 1,731 5,899 9,006651 350 1,418 5,718 8,137
Operating leases 32 30 22 15 11 14 124
Drilling obligations 173 17 -- -- -- -- 190
Firm transportation agreements 93 82 65 49 42 219 550
-------- -------- -------- -------- -------- -------- --------96 90 73 56 48 239 602
------ ------ ------ ------ ------ ------ -------
Total $ 298 129 580 947 1,784 6,132 9,870
======== ======== ======== ======== ======== ======== ========301 137 746 421 1,477 5,971 9,053
====== ====== ====== ====== ====== ====== =======
Firm transportation agreements represent "ship or pay" arrangements
whereby Devon has committed to ship certain volumes of gas for a fixed
transportation fee. Devon has entered into these agreements to ensure that Devon
can get its gas production to market. Devon expects to have sufficient volumes
to ship to satisfy the firm transportation agreements, so that Devon will be
receiving equivalent value for the firm transportation payments that it will
make.
The above table does not include $107$99 million of letters of credit that
have been issued by commercial banks on Devon's behalf which, if funded, would
become borrowings under Devon's revolving credit facility. Most of these letters
of credit have been granted by Devon's financial institutions to support Devon's
Canadian drilling commitments. The $9.0$8.1 billion of long-term debt shown in the
table excludes $118$105 million of discounts included in the March 31,June 30, 2002, book
balance of the debt.
REVISIONS TO 2002 ESTIMATES
On March 19,May 15, 2002, Devon filed a Form 10-K10-Q that provided forward-looking
estimates for the full year 2002. Full-year revisionsRevisions to certain of those previous
estimates are provided herein. The revised estimates reflect the impact
of Devon's acquisition of Mitchell Energy & Development Corp. on January 24,
2002 and the anticipated timing of the sales of the Disposition Properties. The
full-year revisions also include adjustments to previous estimates, when
required,herein to reflect actual year-to-date results.
The revised forward-looking statements provided in this discussion are
based on management's examination of historical operating trends, the
information which was used to prepare the December 31, 2001 reserve reports and
other data in Devon's possession or available from third parties. Devon cautions
that its future oil, natural gas and NGL production, revenues and expenses are
subject to all of the risks and uncertainties normally incident to the
exploration for and development and production and sale of oil, gas and NGLs.
These risks include, but are not limited to, price volatility, inflation or lack
of availability of goods and services,
32
environmental risks, drilling risks, regulatory changes, the uncertainty
inherent in estimating future oil and gas production or reserves, and other
risks as outlined below. Additionally, Devon cautions that its future gas
services revenues and expenses are subject to all of the risks and uncertainties
normally incident to the gas services business. These risks include, but are not
limited to, price volatility, environmental risks, regulatory changes, the
uncertainty inherent in estimating future processing volumes and pipeline
throughput, and other risks as outlined below. Also, the financial results of
Devon's foreign operations are subject to currency exchange rate risks.
Additional risks are discussed below in the context of line items most affected
by such risks.
SPECIFIC ASSUMPTIONS AND RISKS RELATED TO PRICE AND PRODUCTION
ESTIMATES Prices for oil, natural gas and NGLs are determined primarily by
prevailing market conditions. Market conditions for these products are
influenced by regional and worldwide economic conditions, weather and other
substantially variable factors. These factors are beyond Devon's control and are
difficult to predict. In addition to volatility in general, Devon's oil, gas and
NGL prices may vary considerably due to differences between regional markets,
transportation availability and demand for different grades of oil, gas and
NGLs. Substantially all of Devon's revenues are attributable to sales,
processing and transportation of these three commodities. Consequently, Devon's
financial results and resources are highly influenced by price volatility.
Estimates for Devon's future production of oil, natural gas and NGLs
are based on the assumption that market demand and prices for oil and gas will
continue at levels that allow for profitable production of these products. There
can be no assurance of such stability. Also, Devon's international production of
oil, natural gas and NGLs is governed by payout agreements with the governments
of the countries in which Devon operates. If the payout under these agreements
is attained earlier than projected, Devon's net production and proved reserves
in such areas could be reduced.
Estimates for Devon's future processing and transport of natural gas
and NGLs are based on the assumption that market demand and prices for gas and
NGLs will continue at levels that allow for profitable processing and transport
of these products. There can be no assurance of such stability.
The production, transportation, processing and marketing of oil,
natural gas and NGLs are complex processes which are subject to disruption due
to transportation and processing availability, mechanical failure, human error,
meteorological events including, but not limited to, hurricanes, and numerous
other factors. The following forward-looking statements were prepared assuming
demand, curtailment, producibility and general market conditions for Devon's
oil, natural gas and NGLs during 2002 will be substantially similar to those of
the first three months of 2002, unless otherwise noted. Given the general
limitations expressed herein, Devon's forward-looking statements for 2002 are
set forth below. Unless otherwise noted, all of the following dollar amounts are
expressed in U.S. dollars. Those amounts related to Canadian operations have
been converted to U.S. dollars using an exchange rate of $0.65 U.S. dollar to
$1.00 Canadian dollar. The actual
33
2002 exchange rate may vary materially from this estimated rate. Such variations
could have a material effect on the following Canadian estimates.
The following forward-looking data excludes the financial and operating
effects of potential property acquisitions or divestitures, except for the
Mitchell acquisition and except as discussed in "Property Acquisitions and
Divestitures". The timing and ultimate results of such acquisition and
divestiture activity is difficult to predict, and may vary materially from that
discussed in this report.
GEOGRAPHIC REPORTING AREAS FOR 2002 The following estimates of
production, average price differentials and capital expenditures are provided
separately for each of the following geographic areas:
o the United States;
o Canada; and
o International, which encompasses all oil and gas properties that
lie outside of the United States and Canada.
YEAR 2002 POTENTIAL OPERATING ITEMS
The estimates related to oil, gas and NGL production, operating costs
and DD&A set forth in the following paragraphs are based on estimates for
Devon's properties other than those that have been designated for possible sale
(See "Property Acquisitions and Divestitures"). Therefore, the following
estimates exclude the results of the potential sale properties for the entire
year. Also, all of the estimates related to price swaps and costless price
collars are as of April 30,July 31, 2002.
40
OIL, GAS AND NGL PRODUCTION Set forth in the following paragraphs are
individual estimates of Devon's oil, gas and NGL production for 2002. On a
combined basis, Devon estimates its 2002 oil, gas and NGL production will total
between 175.2173.8 and 185.2182.9 MMBoe. Of this total, approximately 92% is estimated to
be produced from reserves classified as proved at December 31, 2001.
OIL PRODUCTION Devon expects its oil production to total between 36.536.2
and 38.638.1 MMBbls. Of this total, approximately 95% is estimated to be produced
from reserves classified as proved at December 31, 2001. The expected ranges of
production by area are as follows:
(MMBbls)
------------
United States 19.719.8 to 20.8
Canada 14.914.7 to 15.815.5
International 1.91.7 to 2.01.8
OIL PRICES - FIXED Through certain forward oil sales agreements assumed
in the 2000 Santa Fe Snyder merger, the price on a portion of Devon's 2002 oil
production has been fixed.
34
These agreements fixed the price on 2.5 MMBbls of
2002 oil production at an average price of $16.84 per Bbl. It should be noted
that these forward sales apply only to production in the first eight months of
2002.
Devon has executed price swaps attributable to 8 MMBbls of domestic
production at an average price of $23.85 per Bbl. Additionally, Devon has
entered into price swaps attributable to Canadian production of 1.6 MMBbls at an
average price of $20.33 per Bbl.
OIL PRICES - FLOATING For oil production for which prices have not been
fixed, Devon's average prices are expected to differ from the NYMEX price as set
forth in the following table.
EXPECTED RANGE OF OIL PRICES
LESS THAN NYMEX PRICE
----------------------------
United States ($3.15) to ($2.15)
Canada ($5.50) to ($3.50)
International ($3.30)3.90) to ($2.30)2.90)
Devon has also entered into costless price collars that set a floor
pricesprice and a ceiling price for 7.3 MMBbls of United States oil production that
otherwise is subject to floating prices. The collars have weighted average floor
and ceiling prices per Bbl of $23.00 and $28.19, respectively. The floor and
ceiling prices are based on the NYMEX price. The NYMEX price is the monthly
average of settled prices on each trading day for West Texas Intermediate Crude
oil delivered at Cushing, Oklahoma. If the NYMEX price is outside of the ranges
set by the floor and ceiling prices in the various collars, Devon and the
counterparty to the collars will settle the difference. Any such settlements
will either increase or decrease Devon's oil revenues for the period. Because
Devon's oil volumes are often sold at prices that differ from the NYMEX price
due to differing quality (i.e., sweet crude versus sour crude) and
transportation costs from different geographic areas, the floor and ceiling
prices of the various collars do not reflect actual limits of Devon's realized
prices for the production volumes related to the collars.
41
GAS PRODUCTION Devon expects its gas production to total between 733720
Bcf and 775758 Bcf. Of this total, approximately 90% is estimated to be produced
from reserves classified as proved at December 31, 2001. The expected ranges of
production are as follows:
(BCF)
----------
United States 465454 to 492478
Canada 268266 to 283280
GAS PRICES - FIXED Through various price swaps and fixed-price physical
delivery contracts, Devon has fixed the price it will receive on a portion of
its natural gas production. The following tables include information on this
fixed-price production. Where necessary, the prices have been adjusted for
certain transportation costs that are netted against the prices recorded by
Devon, and the prices have also been adjusted for the Btu content of the gas
hedged.
35
FIRST HALF OF 2002 SECOND HALF OF 2002
-------------------------- ------------------------------------------------- -----------------------
Mcf/DAY PRICE/Mcf Mcf/DAY PRICE/Mcf
--------- --------- --------- ---------
United States 268,509298,841 $ 2.91 263,9282.86 279,091 $ 2.962.94
Canada 222,300209,003 $ 2.07 175,5482.15 175,986 $ 2.012.11
GAS PRICES - FLOATING For the natural gas production for which prices
have not been fixed, Devon's average prices are expected to differ from the
NYMEX price as set forth in the following table. The NYMEX price is determined
to be the first-of-month South Louisiana Henry Hub price index as published
monthly in Inside FERC.
EXPECTED RANGE OF GAS PRICES
GREATER THAN (LESS THAN) NYMEX PRICE
------------------------------------
United States ($0.45)0.65) to $0.05($0.15)
Canada ($0.70)0.80) to ($0.20)0.30)
Devon has also entered into costless price collars that set a floor and
ceiling price for a portion of its natural gas production that otherwise is
subject to floating prices. If the applicable monthly price indices are outside
of the ranges set by the floor and ceiling prices in the various collars, Devon
and the counterparty to the collars will settle the difference. Any such
settlements will either increase or decrease Devon's gas revenues for the
period. Because Devon's gas volumes are often sold at prices that differ from
the related regional indices, and due to differing Btu contents of gas produced,
the floor and ceiling prices of the various collars do not reflect actual limits
of Devon's realized prices for the production volumes related to the collars.
Devon has entered into costless collars concerning its 2002 gas
production. To simplify presentation, these collars have been aggregated in the
following table according to similar floor prices. The floor and ceiling prices
shown are weighted averages of the various collars in each aggregated group.
The prices shown in the following table have been adjusted to a
NYMEX-based price, using Devon's estimates of 2002 differentials between NYMEX
and the specific regional indices upon which the collars are based. The floor
and ceiling prices related to the domestic collars are based on various regional
first-of-the-month price indices as published monthly by Inside FERC. The floor
and ceiling prices related to the Canadian collars are based on the AECO index
as published by the Canadian Gas Price Reporter.
3642
FIRST HALF OF 2002 SECOND HALF OF 2002
---------------------------------- ----------------------------------------------------------------------- -------------------------------------
AVERAGE AVERAGE AVERAGE AVERAGE
FLOOR CEILING FLOOR CEILING
PRICE PRICE PRICEPER PRICE PER PRICE PER PERPRICE PER
AREA (RANGE OF FLOOR PRICES) MMBtu/DAY MMBtu MMBtu MMBtu/DAY MMBtu MMBtu
----------------------------- ----------------------------- --------- -------- -------- --------- -------- ----------------- --------- --------- ---------
United States ($3.38 - $3.65) 285,000 $ 3.51 $ 7.37 285,000 $ 3.51 $ 7.37
United States ($3.25 - $3.25) -- $ -- $ -- 40,000 $ 3.25 $ 5.07
United States ($2.95 - $3.05) 130,000 $ 3.00 $ 4.51 ----- $ -- $ --
United States ($2.75 - $2.78) 35,000 $ 2.76 $ 3.72 35,000 $ 2.76 $ 3.72
Canada ($3.45 - $3.63) 23,705 $ 3.563.60 $ 6.736.80 23,705 $ 3.563.60 $ 6.736.80
Canada ($3.28 - $3.29) -- $ -- $ -- 25,011 $ 3.28 $ 5.09
Canada ($3.10 - $3.23) 9,481 $ 3.173.21 $ 4.41 ---4.46 -- $ -- $ --
Canada ($2.63 - $2.90) 34,481 $ 2.702.73 $ 3.793.82 25,000 $ 2.632.65 $ 3.583.60
NGL PRODUCTION Devon expects its production of NGLs to total between
16.517.6 million barrels and 17.418.5 million barrels. Of this total, 98% is estimated
to be produced from reserves classified as proved at December 31, 2001. The
expected ranges of production are as follows:
(MMBbls)
------------
United States 11.912.9 to 12.513.6
Canada 4.64.7 to 4.9
MARKETING AND MIDSTREAM REVENUES AND EXPENSES Devon's marketing and
midstream revenues and expenses are derived from its natural gas processing
plants and natural gas transport pipelines. These revenues and expenses vary in
response to several factors. The factors include, but are not limited to,
changes in production from wells connected to the pipelines and related
processing plants, changes in the absolute and relative prices of natural gas
and NGLs, provisions of the contract agreements and the amount of repair and
workover activity required to maintain anticipated processing levels.
These factors increase the uncertainty inherent in estimating future
marketing and midstream revenues and expenses. Given these uncertainties, Devon estimates that 2002
marketing and midstream revenues will be between $900$966 million and $965$999 million
and marketing and midstream expenses will be between $740$800 million and $780$826
million.
PRODUCTION AND OPERATING EXPENSES Devon's production and operating
expenses include lease operating expenses, transportation costs and production
taxes. These expenses vary in response to several factors. Among the most
significant of these factors are additions to or deletions from Devon's property
base, changes in production tax rates, changes in the general price level of
services and materials that are used in the operation of the properties and the
amount of repair and workover activity required. Oil, natural gas and NGL prices
also have an effect on lease operating expense and impact the economic
feasibility of planned workover projects.
Given these uncertainties, Devon estimates that lease operating expenses
will be between $545 million and $571 million, transportation costs will be
between $153 million and $160 million
37
and production taxes will be between 3.2% and 3.7% of consolidated oil, natural
gas and NGL revenues, excluding revenues related to hedges upon which production
taxes are not incurred.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2002 oil and gas
property DD&A rate will depend on various factors. Most notable among such
factors are the amount of proved reserves that will be added from drilling or
acquisition efforts compared to the costs incurred for such efforts, and the
revisions to Devon's year-end 2001 reserve estimates that, based on prior
experience, are likely to be made during 2002.
Oil and gas property related DD&A expense is expected to be between
$1.0 billion and $1.2 billion. Additionally, Devon expects its
DD&A expense related to non-oil and gas property fixed assets to total between
$94$100 million and $98$104 million. This range includes $62$64 million to $65$68 million
related to marketing and midstream assets.
Based on these DD&A amounts and the production
estimates set forth earlier, Devon expects its consolidated DD&A rate will be
between $6.40 per Boe and $6.76 per Boe.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's G&A includes the
costs of many different goods and services used in support of its business.
These goods and services are subject to general price level increases or
decreases. In addition, Devon's G&A varies with its level of activity and the
related staffing needs as well as with the amount of professional services
required during any given period. Should Devon's needs or the prices of the
required goods and services differ significantly from current expectations,
actual G&A could vary materially from the estimate. Given these limitations,Devon estimates that
consolidated G&A is expected towill be between $189$200 million and $198 million.
INTEREST EXPENSE Future interest rates, debt outstanding and oil,
natural gas and NGL prices have a significant effect on Devon's interest
expense. Devon can only marginally influence the prices it will receive in 2002
from sales of oil, natural gas and NGLs and the resulting cash flow. The
proceeds and the timing of the property sales in 2002 will also affect interest
expense. These factors increase the margin of error inherent in estimating
future interest expense. Other factors which affect interest expense, such as
the amount and timing of capital expenditures, are within Devon's control.
Assuming no changes in fixed-rate debt balances during the remainder of
2002 except as discussed herein, Devon's average balance of fixed rate debt
during 2002 will be $6.3 billion. The interest expense in 2002 related to this
fixed-rate debt will be approximately $464 million. This fixed-rate debt removes
the uncertainty of future interest rates from some, but not all, of Devon's
long-term debt. Devon's floating rate debt is discussed in the following
paragraphs.
After completion of the Mitchell acquisition, Devon had 100% of its
$3.0 billion senior unsecured term loan credit facility borrowed. Interest on
borrowings under this facility may be based, at Devon's option, on LIBOR plus a
margin determined by Devon's long-term senior unsecured debt ratings. Regardless
of the current debt ratings, the margin for borrowings based
38
on LIBOR will be 100 basis points until June 17, 2002. As of May 3, 2002, the
average interest rate on this facility was 2.9% and the current balance was $1.7
billion.
From time to time, Devon borrows under its $1 billion credit
facilities. Borrowings under the U.S. facility, currently set at $725 million,
may be borrowed at various rate options including LIBOR plus a margin with
interest periods of up to six months. Borrowings under the Canadian facility,
currently set at $275 million, may be made at various rate options including
LIBOR plus a margin with interest periods up to six months, or Bankers
Acceptances plus a margin with interest periods of 30 to 180 days. The current
LIBOR margin ranges from 45.0 to 47.5 basis points and the current Bankers
Acceptance margin is 45.0 basis points. There were no borrowings under these
facilities at March 31, 2002.
From time to time, Devon also borrows under its commercial paper
facility. Total borrowings under the $725 million U.S. facility and the
commercial paper program cannot exceed $725 million. The total borrowed under
the commercial paper program was $156 million at March 31, 2002, at an average
interest rate of 2.6%. Debt outstanding under this program is generally borrowed
for seven to 90 day periods, and may be borrowed up to 365 days, at prevailing
commercial paper market rates.
EFFECTS OF CHANGES IN FOREIGN CURRENCY RATES In the October 2001
Anderson acquisition, Devon's subsidiary assumed $400 million of long-term debt
which is denominated in U.S. dollars. This debt matures in 2011. Changes in the
exchange rate between the U.S. dollar and the Canadian dollar from October 15,
when Devon acquired Anderson, to the dates of repayment will increase or
decrease the expected amount of Canadian dollars eventually required to repay
the debt. Such changes in the Canadian dollar equivalent balance of the debt are
required to be included in determining net earnings for the period in which the
exchange rate changes. Because of the variability of the exchange rate, it is
not possible to estimate the effect which will be recorded in 2002. However, for
every $0.01 change in the exchange rate, Devon will record either revenue or
expense of approximately $9 million Canadian dollars. The resulting revenue or
expense in U.S. dollars will depend on the currency exchange rate in effect
throughout the year.
With the devaluation of the Argentine peso in January 2002, changes in
the exchange rate between the U.S. dollar and the Argentine peso will also
result in gains or losses for the period in which the exchange rate changes. The
functional currency of Devon's Argentine subsidiary is the U.S. dollar. As a
result, changes in the exchange rate between the U.S. dollar and the Argentine
peso will increase or decrease the expected amount of Argentine pesos eventually
collected or paid for transactions that are settled in pesos. Because of the
variability of the exchange rate, it is not possible to estimate the effect
which will be recorded in 2002. The resulting revenue or expense in U.S. dollars
will depend on the currency exchange rate in effect throughout the year.
39
OTHER INCOME Devon's other income in 2002 is expected to be between $32
million and $36$210 million.
INCOME TAXES Devon's financial income tax rate in 2002 will vary
materially depending on the actual amount of financial pre-tax earnings. There
are certain tax deductions and credits that will have a fixed impact on 2002's
income tax expense regardless of the level of pre-tax earnings that are
produced. Additionally, any gains or losses which may be recognized from the
sale of the Disposition Properties has been excluded from these estimates of
income taxes. Given these uncertainties, Devon estimates that its consolidated financial income tax
rate in 2002 will be between 15%20% and 35%40%. The current income tax rate is
expected to be between 15% and 25%. The deferred income tax rate is expected to
be between 5% and 15%. The deferred income tax
rate is expected to be between 10% and 20%. Significant changes in estimated
capital expenditures, production levels of oil, gas and NGLs,These rates exclude the prices of such
products, marketing and midstream revenues, or anyeffects of the various expense items
could materially alterCanadian writedown
and property sales as discussed in the following paragraph.
The preceding estimated rates exclude the effect of the aforementionedsecond quarter
2002 Canadian reduction of carrying value of oil and gas properties. This
reduction resulted in a reduction of pretax income $651 million and a deferred
tax deductionsbenefit of $267 million. These estimated tax rates also exclude the effects
of domestic property sales. These domestic property sales result in gains for
tax purposes, but there is no corresponding financial gain or loss because Devon
follows the full-cost method of accounting. As a result, 2002 current taxes are
expected to be increased from $105 million to $115 million for these domestic
property sales and credits on 2002's financial income tax rates.deferred taxes are expected to be decreased by the same
amount.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Devon follows the
full cost method of accounting for its oil and gas properties. Under the full
cost method, Devon's net
43
book value of oil and gas properties, less related deferred income taxes (the
"costs to be recovered"), may not exceed a calculated "full cost ceiling." The
ceiling limitation is the discounted estimated after-tax future net revenues
from oil and gas properties plus the lower of cost or fair value of unproved
properties. The ceiling is imposed separately by country. In calculating future
net revenues, current prices and costs are generally held constant indefinitely.
The costs to be recovered are compared to the ceiling on a quarterly basis. If
the costs to be recovered exceed the ceiling, the excess is written off as an
expense. An expense recorded in one period may not be reversed in a subsequent
period even though higher oil and gas prices may have increased the ceiling
applicable to the subsequent period.
Because of the volatile nature of oil and gas prices, it is not
possible to predict whether Devon will incur a full cost writedown in future
periods. Because the ceiling calculation dictates that prices in effect as of
the last day of the applicable quarter are held constant indefinitely, the
resulting value is not indicative of the true fair value of the reserves. Oil
and natural gas prices have historically been cyclical and, on any particular
day at the end of a quarter, can be either substantially higher or lower than
Devon's long-term price forecast that is a barometer for true fair value.
Therefore, oil and gas property writedowns 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.
Devon recorded writedowns to its domestic and Canadian oil and gas properties as of
December 31, 2001.June 30, 2002, after Canadian gas prices dropped sharply during the last half of
June 2002. The year-end 2001June 30, 2002, reference prices used to calculatein the Canadian ceiling
calculation, expressed in Canadian dollars, were a NYMEX oil price of $19.84C$40.79 per
barrel of oil and a Henry Hub gasan AECO price of $2.65C$2.17 per MMBtu. If oil or gas prices at the endMcf of future quarters
drop below these year-end 2001 prices, or if Devon reduces its estimatesgas. Volatility of
proved reserve quantities, further writedowns would likely occur. Also, in
January
40
2002, Devon closed its merger with Mitchell. The oil and gas properties acquired
in this transaction were recorded at their estimated fair value. The fair values
were based on Devon's estimates of future oil and
gas prices and these
estimated prices were higher than the year-end 2001 market prices for oil and
gas. This increases the likelihood that Devon could incur furtherprevents an accurate estimate of whether additional writedowns of its domestic oil and gas propertieswill
occur in the future.future periods.
PROPERTY ACQUISITIONS AND DIVESTITURES Though Devon has completed
several major property acquisitions in recent years, these transactions are
opportunity driven. Thus, Devon does not "budget," nor can it reasonably
predict, the timing or size of such possible acquisitions, if any, other than
the Mitchell acquisition closed on January 24, 2002.
During 2002, Devon estimates that it will sell certain oil and gas
properties (the "Disposition Properties") for between $1.2$1.3 billion and $1.5$1.6
billion. The Disposition Properties are predominantly those that are either
outside of Devon's core operating areas or otherwise do not fit Devon's current
strategic objectives. The Disposition Properties are located in the U.S., Canada
and International areas.
As of May 3,July 31, 2002, Devon has closed sales of Disposition Properties
totaling $604 million$1.3 billion in proceeds, and has signed agreements for an additional
$598 million of transactions which are expected to close by the end of the
second quarter of 2002.proceeds. In addition, Devon has identified another
$200 million to $300 million of Disposition Properties that could be sold in the
second half of the year.2002.
The estimates of Devon's 2002 results previously set forth in this
report and previous reports exclude any results from the Disposition Properties.
The Disposition Properties' actual contribution to Devon's 2002 operating
results will depend upon when the transactions to sell the Disposition
Properties are actually closed. The following table presents Devon's estimates
of the Disposition Properties' quarterly operating results. For those transactions that are
currently under contract but not yet closed, the following table assumes that
such transactions will close on June 30, 2002. The table does not includealso
includes estimated third quarter operating results of the $200 to $300 million
of various Disposition Properties that, if sold, are not
expected to close untilduring
the second half of 2002.
44
The following table includes production and expense estimates from
International Disposition Properties. However, if and when these properties are
ultimately sold, the financial presentation of the related operating results
will differ. Pursuant to Statement of Financial Accounting Standards No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets, the
International assets to be sold constitute a "component of an entity." As such,
in the period in which such International properties are sold, the related
operating results will beare reported as discontinued operations. The prior periods'
operating results related to such assets will also be reclassified and reported
as discontinued operations. Therefore, upon the sale of these International
Disposition Properties, the individual historical amounts for revenues and
expenses of these properties will beare netted and reported as discontinued operations.
The results of the domestic and Canadian Disposition Properties will not be
presented as discontinued operations due to significant continuing operations in
the United States and Canada.
41
EXPECTED RANGES
------------------------------------------------------------------------------
1ST QUARTER 2ND QUARTER 3RD QUARTER
2002 2002 ----------- -----------2002
------------ ------------ ------------
OIL (MMBbls)
United States 1.5 1.41.6 1.6 --
Canada 1.1 0.3 0.0 to 1.6
Canada 0.8 0.2 to 0.30.1
International 1.7 0.90.8 0.4 to 1.00.5
Total 4.0 2.54.4 2.7 0.4 to 2.90.6
GAS (Bcf)
United States 11 1112 12 0 to 121
Canada 45 2 1 to 2
International 2 2 1 to 2
Total 17 1319 16 2 to 165
NGLS (MMBbls)
United States 0.4 0.1 to 0.20.3 --
Canada 0.1 0 to 0.1 --
International -- -- --
Total 0.5 0.1 to 0.30.4 --
LEASE OPERATING EXPENSES (IN MILLIONS)
United States $ 2022 $ 2117 $ 0 to 221
Canada 10 25 0 to 1
International 15 6 3 International 12 8 to 94
Total 42 3147 28 3 to 346
TRANSPORTATION COSTS (IN MILLIONS)
United States $ 1 $ 0 to 1 --
Canada 1 0 to 1 --
International -- -- --
Total 2 1 to 2 --
DD&A (IN MILLIONS)
United States $ 2426 $ 23 $ 1 to 252
Canada 98 4 0 to 1
International 8 4 3 to 4
International 8 5Total 42 31 4 to 6
Total 41 31 to 357
Additionally, the estimates of Devon's 2002 results previously set
forth in this report exclude the following oil and gas costless price collars
which were entered into at the request of the expected purchaser of the
Disposition Properties located in the United States. If this sale is
consummated, these collars will transfer to the purchaser on the closing date.
If this sale is not completed, Devon will retain these price collars. The oil
collar is for 13,000 barrels per day from May 2002 through December 2002. The
collar has a
4245
floor and ceiling price per barrel of $24.00 and $26.80, respectively. The floor
and ceiling prices are based on the NYMEX price. The gas collar is for 65,000
MMBtu per day from May 2002 through December 2002. The collar has a floor and
ceiling price per MMBtu of $3.25 and $3.60, respectively. The prices on the gas
collar have been adjusted to a NYMEX-based price, using Devon's estimate of 2002
differentials between NYMEX and the specific regional index upon which the
collar is based.
YEAR 2002 POTENTIAL CAPITAL EXPENDITURES AND OTHER CASH USES
CAPITAL EXPENDITURES Though Devon has completed several major property
acquisitions in recent years, these transactions are opportunity driven. Thus,
Devon does not "budget", nor can it reasonably predict, the timing or size of
such possible acquisitions, if any, other than the Mitchell acquisition.
Devon's capital expenditures budget is based on an expected range of
future oil, natural gas and NGL prices as well as the expected costs of the
capital additions. Should actual prices differ materially from Devon's
expectations for its future production, some projects may be accelerated or
deferred and, consequently, may increase or decrease total 2002 capital
expenditures. In addition, if the actual costs of the budgeted items vary
significantly from the anticipated amounts, actual capital expenditures could
vary materially from Devon's estimates.
Given the limitations discussed, the company expects its 2002 capital
expenditures for drilling and development efforts, plus related facilities, to
total between $1.3 billion and $1.5 billion. These amounts include between $495
million and $595 million for drilling and facilities costs related to reserves
classified as proved as of year-end 2001. In addition, these amounts include
between $530 million and $600 million for other low risk/reward projects and
between $300 million and $350 million for new, higher risk/reward projects. Low
risk/reward projects include development drilling that does not offset currently
productive units and for which there is not a certainty of continued production
from a known productive formation. Higher risk/reward projects include
exploratory drilling to find and produce oil or gas in previously untested fault
blocks or new reservoirs.
The following table shows expected drilling and facilities expenditures
by geographic area.
DRILLING AND PRODUCTION FACILITIES EXPENDITURES
------------------------------------------------------------------------
UNITED STATES CANADA INTERNATIONAL TOTAL
------------ ------------- ------------- -----------------
($ in millions)
Related to Proved Reserves $ 435 - $495 $ 15 - $ 35 $ 45 - $ 65 $ 495 - $ 595
Lower Risk/Reward Projects $ 275 - $305 $ 255 - $ 285 $ 0 - $ 10 $ 530 - $ 600
Higher Risk/Reward Projects $ 70 - $ 80 $ 210 - $ 240 $ 20 - $ 30 $ 300 - $ 350
------------ ------------- ------------ -----------------
Total $ 780 - $880 $ 480 - $ 560 $ 65 - $ 105 $ 1,325 - $ 1,545
============ ============= ============ =================
In addition to the above expenditures for drilling and development,
Devon expects to spend between $135 million and $165 million on its marketing
and midstream assets, which include its oil pipelines, gas processing plants,
CO2 removal facilities and gas transport pipelines. Devon also expects to
capitalize between $85 million and $105 million of G&A expenses in accordance
with the full cost method of accounting. Devon also expects to pay between $20
43
million and $30 million for plugging and abandonment charges, and to spend
between $15 million and $25 million for other non-oil and gas property fixed
assets.
OTHER CASH USES Devon's management expects the policy of paying a
quarterly common stock dividend to continue. With the current $0.05 per share
quarterly dividend rate and 156 million shares of common stock outstanding after
completion of the Mitchell acquisition, 2002 dividends are expected to
approximate $31 million. Also, Devon has $150 million of 6.49% cumulative
preferred stock upon which it will pay $10 million of dividends in 2002.
IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED. In June
2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations.
SFAS No. 143 requires liability recognition for retirement obligations
associated with tangible long-lived assets, such as producing well sites,
offshore production platforms, and natural gas processing plants. The
obligations included within the scope of SFAS No. 143 are those for which a
company faces a legal obligation for settlement. The initial measurement of the
asset retirement obligation is to be fair value, defined as "the price that an
entity would have to pay a willing third party of comparable credit standing to
assume the liability in a current transaction other than in a forced or
liquidation sale." Devon expects that it will use a valuation technique such as
expected present value to estimate fair value.
The asset retirement cost equal to the fair value of the retirement
obligation is to be capitalized as part of the cost of the related long-lived
asset and allocated to expense using a systematic and rational method.
Devon will be required to adopt SFAS No. 143 effective January 1, 2003
using a cumulative effect approach to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated depreciation.
Devon currently recordsincludes estimated costs of dismantlement, removal,
site reclamation, and other similar activities as part ofin the total costs that are
subject to depreciation, depletion, and amortization andamortization. Devon does not record a
separate asset or liability for such amounts. Devon has not completed the
assessment of the impact that adoption of SFAS No. 143 will have on its
consolidated financial statements. However, Devon expects
the amounts for capitalized oil and gas property costs and asset retirement
obligations will increase.
The FASB issued Statement No. 145, Rescission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, on
April 30, 2002. Statement No. 145 rescinds Statement No. 4, which required all
gains and losses from extinguishment of debt to be aggregated and, if material,
classified as an extraordinary item, net of related income tax effect. Upon
adoption of Statement No. 145, Devon will be required to apply the criteria in
APB Opinion No. 30, Reporting the Results of Operations - Reporting the Effects
of Disposal of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions (Opinion No. 30), in determining
the classification of gains
44
and losses resulting from the extinguishment of debt. Based on that criteria,
Devon does not expect to classify material gains and losses from early
extinguishments of debt as extraordinary items in the future as was reported in
the past. Additionally, Statement No. 145 amends Statement No. 13 to require
that certain lease modifications that have economic effects similar to
sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. StatementSFAS No. 145 will be effective for fiscal years beginning after
May 15, 2002,2002. This statement rescinds SFAS No. 4, Reporting Gains and upon adoption, Devon must reclassifyLosses
From Extinguishment of Debt, and requires that all gains and losses from
extinguishment of debt should be classified as extraordinary items only if they
meet the criteria in APB No. 30. Applying APB No. 30 will distinguish
transactions that are part of an entity's recurring operations from those that
are unusual or infrequent or that meet the criteria for classification as an
extraordinary item. Any gain or loss on extinguishment of debt that was
classified as an extraordinary item in prior period itemsperiods presented that dodoes not
meet the criteria in APB No. 30 for classification as an extraordinary item classification
criteriamust
be reclassified. Devon will adopt the provisions related to the rescission of
SFAS No. 4 as of January 1, 2003.
In 1999, Devon recorded a $4 million extraordinary loss related to the
early extinguishment of long-term debt. Upon adopting SFAS No. 145 in Opinion2003, this
extraordinary loss will be reclassified as interest expense in any presentation
of Devon's results that includes the year 1999.
The FASB issued Statement No. 30.146, Accounting for Costs Associated with
Exit or Disposal Activities, in June 2002. SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs incurred in a Restructuring). SFAS No. 146 applies to
costs incurred in an "exit activity", which includes, but is not limited to, a
restructuring, or a "disposal activity" covered by SFAS No. 144.
46
SFAS No. 146 requires that a liability for a cost associated with an
exit or disposal activity be recognized when the liability is incurred.
Previously, under Issue 94-3, a liability for an exit cost was recognized at the
date of an entity's commitment to an exit plan. Statement No. 146 also
establishes that fair value is the objective for initial measurement of the
liability.
The provisions of SFAS No. 146 are effective for exit or disposal
activities that are initiated after December 31, 2002.
Emerging Issues Task Force Topic 2-03, "Recognition and Reporting of
Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," and No. 00-17, "Measuring the Fair Value of Energy-Related
Contracts in Applying Issue No. 98-10" was issued in June 2002. The Task Force
reached a consensus that all mark-to-market gains and losses on energy trading
contracts should be shown net in the income statement whether or not settled
physically. Companies would be required to disclose the gross transaction
volumes for those energy trading contracts that are physically settled. The
consensus is effective for financial statements issued for periods ending after
July 15, 2002. Upon application of the consensus, comparative financial
statements for prior periods are required to be reclassified to conform to the
consensus. Devon has not engaged in material energy trading and risk management
activities. Rather Devon has engaged in the marketing of Devon's and third party
oil and gas. Should Devon be required to adopt the provisions of EITF 2-03, the
result would have reduced gathering, marketing, and processing revenues and
expenses. The adoption of the consensus would not have an effect on Devon's net
results from operations.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information included in "Quantitative and Qualitative Disclosures
About Market Risk" in Item 7A of Devon's 2001 Annual Report on Form 10-K is
incorporated herein by reference. Such information includes a description of
Devon's potential exposure to market risks, including commodity price risk,
interest rate risk and foreign currency risk. AsThe following information updates
Devon's commodity price risk exposure as of MarchJuly 31, 2002, there have
been no materialfor changes in Devon's market risk exposure from that
disclosed in the 2001 Form 10-K.
45COMMODITY PRICE RISK Devon's major market risk exposure is in the
pricing applicable to its oil and gas production. Realized pricing is primarily
driven by the prevailing worldwide price for crude oil and spot market prices
applicable to its U.S. and Canadian natural gas production. Pricing for oil and
gas production has been volatile and unpredictable for several years.
Devon periodically enters into financial hedging activities with
respect to a portion of its projected oil and natural gas production through
various financial transactions which hedge the future prices received. These
transactions include financial price swaps whereby Devon will receive a fixed
price for its production and pay a variable market price to the contract
counterparty, and costless price collars that 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 and
the counterparty to the collars will settle the difference. These financial
hedging activities are intended to support oil and natural gas prices at
targeted levels and to manage Devon's exposure to oil and gas price
fluctuations. Devon does not hold or issue derivative instruments for trading
purposes.
47
Devon's total hedged positions as of July 31, 2002 are set forth in the
following tables.
PRICE SWAPS Through various price swaps, Devon has fixed the price it
will receive on a portion of its oil and natural gas production in 2002, 2003
and 2004. The following tables include information on this production. Where
necessary, the prices have been adjusted for certain transportation costs that
are netted against the price recorded by Devon, and the price has also been
adjusted for the Btu content of the gas production that has been hedged.
OIL PRODUCTION
-------------------------------------------------
FIRST HALF OF 2002 SECOND HALF OF 2002
---------------------- ----------------------
Bbls/DAY PRICE/Bbl Bbls/DAY PRICE/Bbl
-------- --------- -------- ---------
United States 22,000 $ 23.85 22,000 $ 23.85
Canada 4,350 $ 20.33 4,350 $ 20.33
GAS PRODUCTION
---------------------------------------------------
FIRST HALF OF 2002 SECOND HALF OF 2002
----------------------- -----------------------
Mcf/DAY PRICE/Mcf Mcf/DAY PRICE/Mcf
--------- --------- --------- ---------
United States 298,841 $ 2.86 279,091 $ 2.94
Canada 39,009 $ 2.17 34,546 $ 2.29
FIRST HALF OF 2003 SECOND HALF OF 2003
----------------------- -----------------------
Mcf/DAY PRICE/Mcf Mcf/DAY PRICE/Mcf
--------- --------- --------- ---------
United States 100,000 $ 3.42 100,000 $ 3.42
Canada -- $ -- -- $ --
COSTLESS PRICE COLLARS Devon has also entered into costless price
collars that set a floor and ceiling price for a portion of its 2002 and 2003
oil and natural gas production. The following tables include information on
these collars for each geographic area. The floor and ceiling prices related to
domestic oil production are based on NYMEX. The NYMEX price is the monthly
average of settled prices on each trading day for West Texas Intermediate Crude
oil delivered at Cushing, Oklahoma. The gas prices shown in the following table
have been adjusted to a NYMEX-based price, using Devon's estimates of
differentials between NYMEX and the specific regional indices upon which the
collars are based. The floor and ceiling prices related to the domestic collars
are based on various regional first-of-the-month price indices as published
monthly by Inside FERC. The floor and ceiling prices related to the Canadian
collars are based on the AECO index as published by the Canadian Gas Price
Reporter.
If the applicable monthly price indices are outside of the ranges set
by the floor and ceiling prices in the various collars, Devon and the
counterparty to the collars will settle the difference. Any such settlements
will either increase or decrease Devon's gas revenues for the period. Because
Devon's gas volumes are often sold at prices that differ from the related
regional indices, and due to differing Btu content of gas production, the floor
and ceiling prices of the various collars do not reflect actual limits of
Devon's realized prices for the production volumes related to the collars.
The floor and ceiling prices in the following tables are weighted
averages of all the collars.
48
OIL PRODUCTION
-------------------------------------------------------------------------------
FIRST HALF OF 2002 SECOND HALF OF 2002
------------------------------------- -------------------------------------
AVERAGE AVERAGE AVERAGE AVERAGE
FLOOR CEILING FLOOR CEILING
PRICE PER PRICE PER PRICE PER PRICE PER
Bbls/DAY Bbl Bbl Bbls/DAY Bbl Bbl
--------- --------- --------- --------- --------- ---------
United States 20,000 $ 23.00 $ 28.19 20,000 $ 23.00 $ 28.19
FIRST HALF OF 2003 SECOND HALF OF 2003
------------------------------------ ------------------------------------
AVERAGE AVERAGE AVERAGE AVERAGE
FLOOR CEILING FLOOR CEILING
PRICE PER PRICE PER PRICE PER PRICE PER
Bbls/DAY Bbl Bbl Bbls/DAY Bbl Bbl
-------- --------- --------- -------- --------- ---------
United States 13,000 $ 21.23 $ 27.87 13,000 $ 21.23 $ 27.87
Canada 13,000 $ 21.38 $ 27.29 13,000 $ 21.38 $ 27.29
GAS PRODUCTION
-------------------------------------------------------------------------------
FIRST HALF OF 2002 SECOND HALF OF 2002
------------------------------------- -------------------------------------
AVERAGE AVERAGE AVERAGE AVERAGE
FLOOR CEILING FLOOR CEILING
PRICE PER PRICE PER PRICE PER PRICE PER
MMBtu/DAY MMBtu MMBtu MMBtu/DAY MMBtu MMBtu
--------- --------- --------- --------- --------- ---------
United States 450,000 $ 3.32 $ 6.27 360,000 $ 3.43 $ 6.77
Canada 67,667 $ 3.10 $ 4.95 73,716 $ 3.17 $ 5.13
FIRST HALF OF 2003 SECOND HALF OF 2003
------------------------------------- -------------------------------------
AVERAGE AVERAGE AVERAGE AVERAGE
FLOOR CEILING FLOOR CEILING
PRICE PER PRICE PER PRICE PER PRICE PER
MMBtu/DAY MMBtu MMBtu MMBtu/DAY MMBtu MMBtu
--------- --------- --------- --------- --------- ---------
United States 395,000 $ 3.19 $ 4.67 395,000 $ 3.19 $ 4.67
Canada 140,023 $ 3.30 $ 4.67 140,023 $ 3.30 $ 4.67
FIRST HALF OF 2004 SECOND HALF OF 2004
------------------------------------- -------------------------------------
AVERAGE AVERAGE AVERAGE AVERAGE
FLOOR CEILING FLOOR CEILING
PRICE PER PRICE PER PRICE PER PRICE PER
MMBtu/DAY MMBtu MMBtu MMBtu/DAY MMBtu MMBtu
--------- --------- --------- --------- --------- ---------
United States 20,000 $ 3.25 $ 5.78 20,000 $ 3.25 $ 5.78
Canada 30,011 $ 3.37 $ 5.65 30,011 $ 3.37 $ 5.65
FIXED-PRICE PHYSICAL DELIVERY CONTRACTS In addition to the commodity
hedging instruments described above, Devon also manages its exposure to oil and
gas price risks by periodically entering into fixed-price contracts.
The price Devon will receive on a portion of its 2002 oil production
has been fixed through certain forward oil sales assumed in the 2000 Santa Fe
Snyder merger. From January
49
2002 through August 2002, 311,000 barrels of oil production per month have been
fixed at an average price of $16.84 per barrel.
For each of the years 2002 through 2011, Devon has fixed-price gas
contracts that cover approximately 51 Bcf, 16 Bcf, 16 Bcf, 14 Bcf, 14 Bcf, 14
Bcf, 14 Bcf, 14 Bcf, 12 Bcf and 10 Bcf, respectively, of Canadian production.
Thereafter, Devon also has Canadian gas volumes subject to fixed-price contracts
in the years from 2012 through 2016, but the yearly volumes are less than 1 Bcf.
50
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
None
ITEM 2. CHANGES IN SECURITIES
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) Devon's specialannual meeting of stockholders was held in Oklahoma
City, Oklahoma at 10:00 a.m. local time, on Thursday January
24,May 16,
2002.
(b) Proxies for the meeting were solicited pursuant to Regulation
14 under the Securities Exchange Act of 1934, as amended.
There was no solicitation in opposition to the nominees for
election as directors as listed in the proxy statement and all
nominees were elected.
(c) Out of a total of 126,092,673156,126,700 shares of Devon's common stock
outstanding and entitled to vote, 82,282,138143,263,196 shares were
present at the meeting in person or by proxy, representing
approximately 6592 percent of the total outstanding. The only
matter voted upon at the meeting was the approvalelection of four
directors to serve on Devon's board of directors until the
Amended and Restated Agreement and Plan2005 annual meeting of Merger, dated
August 13, 2001, among Devon, Devon NewCo Corporation, Devon
Holdco Corporation, Devon Merger Corporation, Mitchell Merger
Corporation and Mitchell Energy & Development Corp. and the
transactions that it contemplates.stockholders. The results of the vote taken at such meetingtabulation with
respect to each nominee was as follows:
For 80,152,181
Against 1,408,920
Abstain 721,037
AUTHORITY
NOMINEE FOR WITHHELD
------- ----------- ---------
John A. Hill 142,276,683 986,512
William J. Johnson 142,272,629 990,566
Michael M. Kanovsky 141,590,490 1,672,705
Robert A. Mosbacher, Jr 142,250,355 1,012,839
ITEM 5. OTHER INFORMATION
None
4651
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits required by Item 601 of Regulation S-K are as
follows:
None
(b) Reports on Form 8-K:
Filing Date Contents
----------- --------
January 18,Exhibit No.
10.1 Seventh Amendment to U.S. Credit Agreement
dated June 7, 2002 Documents filedby and among Registrant,
Bank of America, N.A., individually and as
administrative agent, and the U.S. Lenders
party to this Amendment
10.2 Amended and Restated Canadian Credit
Agreement dated June 7, 2002 among
Northstar Energy Corporation and Devon
Canada Corporation, as Canadian Borrowers,
Bank of America, N.A. acting through its
Canadian Branch, as Administrative Agent,
and Certain Financial Institutions, as
Lenders
10.3 Credit Agreement dated July 25, 2002, by
and among Northstar Energy Corporation and
Devon Canada Corporation, as Borrowers and
RBC Capital Markets, as Arranger and Royal
Bank of Canada, as Administrative Agent and
Certain Financial Institutions, as Lenders
for the Cdn. $140 million credit facility
10.4 Letter Agreement dated July 25, 2002, by
and among Northstar Energy Corporation and
Devon Canada Corporation, as Borrowers and
Royal Bank of Canada acting through its
Canadian Branch , as Lender for the Cdn.
$10 million credit facility
99.1 Certification of J. Larry Nichols, Chief
Executive Officer of Registrant, pursuant
to Rule 42518 U.S.C. Section 1350, as adopted
pursuant to Section 906 of Securitiesthe Sarbanes-
Oxley Act of 1933
January 29, 2002
Year-end 2001 oil and gas reserves and
various gas hedging instruments
entered into in January99.2 Certification of William T. Vaughn, Chief
Financial Officer of Registrant, pursuant
to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
February 6, 2002 Press release announcing 2001 results
April 9, 2002 Exhibits related to Registration
Statement on Form S-3 (File
No. 333-83156) relating to an
aggregate $1.5 billion of securities.
4752
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.
DEVON ENERGY CORPORATION
Date: May 15,August 13, 2002 /s/ Danny J. Heatly
------------------------------------------------------------
Danny J. Heatly
Vice President - Accounting
4853
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.1 Seventh Amendment to U.S. Credit Agreement
dated June 7, 2002 by and among Registrant,
Bank of America, N.A., individually and as
administrative agent, and the U.S. Lenders
party to this Amendment
10.2 Amended and Restated Canadian Credit
Agreement dated June 7, 2002 among
Northstar Energy Corporation and Devon
Canada Corporation, as Canadian Borrowers,
Bank of America, N.A. acting through its
Canadian Branch, as Administrative Agent,
and Certain Financial Institutions, as
Lenders
10.3 Credit Agreement dated July 25, 2002, by
and among Northstar Energy Corporation and
Devon Canada Corporation, as Borrowers and
RBC Capital Markets, as Arranger and Royal
Bank of Canada, as Administrative Agent and
Certain Financial Institutions, as Lenders
for the Cdn. $140 million credit facility
10.4 Letter Agreement dated July 25, 2002, by
and among Northstar Energy Corporation and
Devon Canada Corporation, as Borrowers and
Royal Bank of Canada acting through its
Canadian Branch , as Lender for the Cdn.
$10 million credit facility
99.1 Certification of J. Larry Nichols, Chief
Executive Officer of Registrant, pursuant
to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
99.2 Certification of William T. Vaughn, Chief
Financial Officer of Registrant, pursuant
to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002