SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED) JULY 17, 2002
(January 24, 2002)
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
Delaware
--------------------------------------------------------------------------------
(State or Other Jurisdiction of Incorporation)
000-30176 73-1567067
------------------------------ --------------------------------------
(Commission File Number) (I.R.S. Employer Identification No.)
20 North Broadway, Suite 1500,
Oklahoma City, Oklahoma 73102-8260
--------------------------------------------------------------------------------
(Address of Principal Executive Offices) (Zip Code)
(405) 235-3611
(Registrant's Telephone Number, Including Area Code)
N/A
(Former Name or Former Address, if Changed Since Last Report)
ITEM 5. OTHER EVENTS
On January 24, 2002, Devon Energy Corporation ("Devon") completed its
acquisition of Mitchell Energy & Development Corp. ("Mitchell"). On January 29,
2002, Devon filed a Form 8-K that included Mitchell's consolidated financial
statements as of September 30, 2001 and for the nine months then ended, as well
as pro forma financial statements for the same periods.
Included in this Form 8-K are updated financial statements including Mitchell's
audited consolidated financial statements as of December 31, 2001 and for the
year then ended, as well as pro forma financial statements for the same period.
The consolidated financial statements of Mitchell and its subsidiaries as of
December 31, 2001 and 2000 and for the years ended December 31, 2001, 2000 and
1999, that are included in this Form 8-K have been audited by Arthur Andersen
LLP, independent public accountants, as indicated in their report included
herein.
This Form 8-K is incorporated by reference in the Registration Statements (File
Nos. 333-68694, 333-32214, 333-47672, 333-44702, 333-39908 and 333-85553) on
Form S-8, the Registration Statement (File No. 333-75206) on Form S-4, and the
Registration Statements (File Nos. 333-85211, 333-50036, 333-50034 and
333-83156) on Form S-3 of Devon. Representatives of Arthur Andersen LLP are not
available to consent to the inclusion of their report on Mitchell's consolidated
financial statements in the aforementioned Registration Statements, and we have
dispensed with the requirement to file their consent in reliance upon Rule 437a
of the Securities Act of 1933. Because Arthur Andersen LLP has not consented to
the inclusion of their report in the aforementioned Registration Statements, you
may not be able to recover against Arthur Andersen LLP under Section 11 of the
Securities Act for any untrue statements of a material fact contained in
Mitchell's consolidated financial statements audited by Arthur Andersen LLP or
any omissions to state a material fact required to be stated therein or
necessary to make the statements therein not misleading.
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS.
(a) Financial Statements of Businesses Acquired.
Audited Consolidated Financial Statements of Mitchell Energy & Development Corp.
and subsidiaries as of December 31, 2001 and 2000 and for the years ended
December 31, 2001, 2000 and 1999
(b) Pro Forma Financial Statements.
Unaudited Devon Energy Corporation Pro Forma Combined Financial Statements as of
December 31, 2001 and for the year then ended
2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
(THIS REPORT IS A COPY OF A REPORT ISSUED BY ARTHUR ANDERSEN LLP ON MARCH 13,
2002. REPRESENTATIVES OF ARTHUR ANDERSEN LLP ARE NOT AVAILABLE TO REISSUE THIS
REPORT FOR THIS FORM 8-K.)
To Mitchell Energy & Development Corp.:
We have audited the accompanying consolidated balance sheets of Mitchell
Energy & Development Corp. (a Texas corporation) and subsidiaries as of December
31, 2001 and 2000, and the related consolidated statements of earnings,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the responsibility of
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Mitchell Energy &
Development Corp. and subsidiaries as of December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
March 13, 2002
3
Mitchell Energy & Development Corp. and Subsidiaries
CONSOLIDATED BALANCE SHEETS (Note 13)
DECEMBER 31, 2001 AND 2000
(dollar amounts in thousands)
2001 2000
---------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents ................................................... $ 15,218 $ 23,451
Trade receivables (net of allowance for doubtful accounts of $2,800 and $381) 111,428 221,946
Federal income taxes receivable ............................................. 41,434 --
Inventories (at lower of cost or market) .................................... 15,471 17,636
Other ....................................................................... 11,568 5,198
---------- ----------
Total current assets ................................................... 195,119 268,231
PROPERTY, PLANT AND EQUIPMENT (at cost less accumulated depreciation,
depletion and amortization of $1,757,361 and $1,559,427 - Note 2)......... 1,658,612 1,206,005
LONG-TERM INVESTMENTS AND OTHER ASSETS ...................................... 57,707 45,529
---------- ----------
$1,911,438 $1,519,765
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt (Note 4) ............................... $ 62,920 $ --
Oil and gas proceeds payable ................................................ 89,245 166,221
Accounts payable ............................................................ 98,743 79,248
Accrued liabilities ......................................................... 56,449 58,670
---------- ----------
Total current liabilities .............................................. 307,357 304,139
---------- ----------
LONG-TERM DEBT (Note 4) ..................................................... 363,055 300,342
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes (Note 5) .............................................. 296,750 203,919
Retirement obligations (Note 8) ............................................. 77,526 71,733
Other ....................................................................... 23,731 19,446
---------- ----------
398,007 295,098
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 3, 6 and 8)
STOCKHOLDERS' EQUITY (Note 10)
Preferred stock, $.10 par value (authorized 10,000,000 shares; none issued)
Common stock, $.10 par value (authorized 200,000,000 shares) (Note 10) ...... 5,386 5,386
Additional paid-in capital .................................................. 155,464 148,154
Retained earnings ........................................................... 766,379 565,132
Other comprehensive loss .................................................... (11,321) (8,896)
Treasury stock, at cost ..................................................... (72,889) (89,590)
---------- ----------
843,019 620,186
---------- ----------
$1,911,438 $1,519,765
========== ==========
-----------------
The accompanying notes are an integral part of these financial statements.
4
Mitchell Energy & Development Corp. and Subsidiaries
CONSOLIDATED STATEMENTS OF EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(in thousands except per-share amounts)
2001 2000 1999
---------- ---------- --------
REVENUES
Exploration and production..................................................... $ 656,404 $ 531,213 $254,009
Gas services................................................................... 1,162,532 1,135,899 623,459
---------- ---------- --------
1,818,936 1,667,112 877,468
---------- ---------- --------
OPERATING COSTS AND EXPENSES (including personnel reduction program
costs of $15,652 in 1999 - Note 9)
Exploration and production (includes $26,029 proved property impairment
charge in 2001; net of litigation provision reversals of $1,200 in 2000
and $14,000 in 1999 - Note 9)............................................... 342,782 239,628 177,862
Gas services (including an asset impairment charge of $10,762 in
2000 - Note 9).............................................................. 1,087,741 1,007,944 548,533
---------- ---------- --------
1,430,523 1,247,572 726,395
---------- ---------- --------
SEGMENT OPERATING EARNINGS (Note 9)............................................ 388,413 419,540 151,073
General and administrative expense (including
personnel reduction program costs of $8,848 in 1999 - Note 9)............... 32,731 43,739 37,626
---------- ---------- --------
TOTAL OPERATING EARNINGS....................................................... 355,682 375,801 113,447
---------- ---------- --------
OTHER EXPENSE
Interest expense............................................................... 22,720 28,765 34,499
Capitalized interest........................................................... (7,534) (2,948) (2,029)
Gains from disposition of property, plant and equipment
(including gains of $4,884 from an asset exchange in 2000 - Note 3, and
$11,527 from the sale of Hell's Hole area properties in 1999 - Note 14)..... (411) (5,022) (16,888)
Other (income) expense......................................................... 1,969 (2,951) (4,133)
---------- ---------- --------
16,744 17,844 11,449
---------- ---------- --------
EARNINGS BEFORE INCOME TAXES................................................... 338,938 357,957 101,998
INCOME TAXES (net of $12,830 prior years' Section 29 tax credits and
$6,293 reversal of certain prior years' deferred taxes in 2000) (Note 5).... 111,139 100,811 34,664
---------- ---------- --------
NET EARNINGS................................................................... $ 227,799 $ 257,146 $ 67,334
========== ========== ========
EARNINGS PER SHARE (Note 12)
Basic ......................................................................... $ 4.56 $ 5.22 $ 1.37
Diluted........................................................................ 4.48 5.13 1.37
AVERAGE COMMON SHARES OUTSTANDING
Basic ......................................................................... 50,000 49,291 49,117
Diluted........................................................................ 50,889 50,084 49,223
-------------------------
The accompanying notes are an integral part of these financial statements.
5
Mitchell Energy & Development Corp. and Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Note 13)
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(dollar amounts in thousands)
Other
Additional Compre-
Common Paid-in Retained hensive Treasury
DOLLAR AMOUNTS Total Stock Capital Earnings Loss Stock
-------------- -------- ------ ---------- -------- ------- ---------
BALANCE, DECEMBER 31, 1998................ $341,282 $5,386 $143,636 $303,774 $(7,364) $(104,150)
Net earnings.............................. 67,334 - - 67,334 - -
Minimum pension liability adjustment
(net of income taxes of $794).......... 1,474 - - - 1,474 -
--------
Comprehensive income................ 68,808
Cash dividends (48 cents per share on
Class A and 53 cents per share
on Class B)............................ (24,916) - - (24,916) - -
-------- ------ -------- -------- ------- ---------
BALANCE, DECEMBER 31, 1999................ 385,174 5,386 143,636 346,192 (5,890) (104,150)
Net earnings.............................. 257,146 - - 257,146 - -
Minimum pension liability adjustment
(net of income taxes of $1,619)........ (3,006) - - - (3,006) -
--------
Comprehensive income................ 254,140
Regular cash dividends (cents per
share - 25.25 on Class A, 26.5 on
Class B and 26.5 on combined shares)... (25,895) - - (25,895) - -
Special cash dividends (25 cents per
share each on Class A and
Class B shares)........................ (12,311) - - (12,311) - -
Treasury stock purchases.................. (2,768) - - - - (2,768)
Exercises of stock options................ 21,846 - 4,518 - - 17,328
-------- ------ -------- -------- ------- ---------
BALANCE, DECEMBER 31, 2000................ $620,186 $5,386 $148,154 $565,132 $ (8,896) $ (89,590)
Net earnings.............................. 227,799 - - 227,799 - -
Minimum pension liability adjustment
(net of income taxes of $1,306)........ (2,425) - - - (2,425) -
Comprehensive income................ 225,374
Cash dividends (53 cents per share)....... (26,552) - - (26,552) - -
Exercises of stock options................ 24,011 - 7,310 - - 16,701
-------- ------ -------- -------- ------- ---------
BALANCE, DECEMBER 31, 2001................ $843,019 $5,386 $155,464 $766,379 $(11,321) $ (72,889)
======== ====== ======== ======== ======== =========
Common Stock Issued Treasury Stock
------------------------- ----------------------- Total Shares
SHARE AMOUNTS Class A Class B Class A Class B Outstanding
------------- ---------- ---------- --------- --------- -----------
BALANCE, DECEMBER 31, 1998 ................ 23,978,077 29,878,077 1,656,437 3,082,450 49,117,267
Other...................................... (5) (5) - - (10)
---------- ---------- --------- --------- ----------
BALANCE, DECEMBER 31, 1999 ................ 23,978,072 29,878,072 1,656,437 3,082,450 49,117,257
Treasury stock purchases................... - - 66,800 32,000 (98,800)
Exercises of stock options................. - - (610,118) (167,642) 777,760
Other...................................... (2) (2) - - (4)
Reclassification of common stock (Note 10). 29,878,070 (29,878,070) 2,946,808 (2,946,808) -
---------- ---------- --------- ---------- ----------
BALANCE, DECEMBER 31, 2000 ................ 53,856,140 - 4,059,927 - 49,796,213
========== ==========
Exercises of stock options................. - (756,808) 756,808
---------- --------- ----------
BALANCE, DECEMBER 31, 2001 ................ 53,856,140 3,303,119 50,553,021
========== ========= ==========
---------------------------
The accompanying notes are an integral part of these financial statements.
6
Mitchell Energy & Development Corp. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(in thousands)
2001 2000 1999
---------- ---------- ----------
OPERATING ACTIVITIES
Net earnings............................................................... $227,799 $ 257,146 $ 67,334
Adjustments to reconcile earnings to cash provided by operating activities
Depreciation, depletion and amortization (including
producing property impairment of $26,029 in 2001)..................... 227,072 144,614 111,641
Exploratory well impairments............................................ 10,050 4,812 2,960
Deferred income taxes................................................... 99,731 54,045 19,552
Distributions in excess of earnings of equity investees................. 3,512 7,060 4,289
Louisiana Chalk asset impairment........................................ - 10,762 -
Accrued personnel reduction program costs............................... - - 17,620
Gains from dispositions of property, plant and equipment................ (411) (5,022) (16,888)
Litigation provision reversals.......................................... - (1,200) (14,000)
Other, net.............................................................. 6,896 (5,989) (2,888)
-------- ---------- ----------
574,649 466,228 189,620
Changes in operating assets and liabilities
Trade receivables..................................................... 109,713 (179,038) 13,012
Inventories........................................................... 2,165 (11,309) 9,328
Federal income taxes receivable....................................... (41,434) - 4,294
Payables.............................................................. (68,590) 97,180 10,421
Accrued liabilities and other......................................... (8,591) 19,193 11,227
-------- ---------- ----------
Cash provided by operating activities................................... 567,912 392,254 237,902
-------- ---------- ----------
INVESTING ACTIVITIES
Capital expenditures ...................................................... (687,218) (302,434) (158,408)
Proceeds from disposition of property, plant and equipment................. 1,408 17,123 44,220
Other, net................................................................. (5,117) (3,015) 3,710
-------- ---------- ----------
Cash used for investing activities.................................... (690,927) (288,326) (110,478)
-------- ---------- ----------
FINANCING ACTIVITIES
Proceeds from issuance of debt............................................. 152,200 - 6,500
Debt repayments............................................................ (26,567) (78,925) (100,000)
Cash dividends (including special dividends of $12,311 in 2000)............ (26,454) (37,840) (24,916)
Proceeds from stock option exercises....................................... 15,603 15,032 -
Treasury stock purchases................................................... - (2,768) -
Other, net................................................................. - - (317)
-------- ---------- ----------
Cash provided by (used for) financing activities...................... 114,782 (104,501) (118,733)
-------- ---------- ----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........................... (8,233) (573) 8,691
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR............................... 23,451 24,024 15,333
-------- ---------- ----------
CASH AND CASH EQUIVALENTS, END OF YEAR..................................... $ 15,218 $ 23,451 $ 24,024
======== ========== ==========
-----------------------------
The accompanying notes are an integral part of these financial statements.
7
Mitchell Energy & Development Corp. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001, 2000 AND 1999
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of operations and principles of consolidation. Mitchell Energy &
Development Corp. and its majority-owned subsidiaries (the "Company") constitute
a large independent energy company engaged in the exploration for and
development and production of natural gas, natural gas liquids, and crude oil
and condensate. The Company also operates natural gas processing plants and
gathering systems in Texas and markets the natural gas liquids extracted by its
plants and the natural gas throughput of its gathering systems. The Company was
acquired by Devon Energy Corporation in January 2002 (see Note 13).
The consolidated financial statements include the accounts of the Company
after the elimination of intercompany accounts and transactions. The equity
method of accounting is used for investments in 20%-to-50%-owned entities (see
Note 3).
Use of estimates. The preparation of financial statements in conformity with
accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosures of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
Revenue recognition. Natural gas, crude oil and condensate, natural gas liquids
and gas gathering and marketing revenues are recorded on the sales method at the
time products are sold or services are provided to third parties. Revenues and
expenses attributable to the Company's NGL purchase and processing contracts are
reported on a gross basis since it takes title to the products and has the risks
and rewards of ownership and its compensation in such transactions is not on a
commission or fee basis. The Company's revenue recognition practices are
consistent with the provisions of Staff Accounting Bulletin No. 101 issued by
the Securities and Exchange Commission in December 1999.
Property, plant and equipment. The Company's exploration and production
activities are accounted for using the "successful efforts" method. Lease
acquisition costs are capitalized as are costs to drill and equip development
wells, including unsuccessful ones. Exploratory drilling costs are initially
capitalized; if proved reserves are not found, such costs are subsequently
impaired. Because of the nature of its drilling, the Company historically has
made such determinations within one year. Geological and geophysical costs and
other exploration costs are charged to expense as incurred. Depreciation,
depletion and amortization (DD&A) of proved oil and gas properties is determined
on a field-by-field basis using physical units of production. Estimated future
costs of dismantlement, restoration and abandonment are considered in
determining DD&A expense.
The Company holds no unproved leases whose costs are individually
significant. Costs of unproved leaseholds are charged to expense based on
historical holding periods and success rates. Leasehold costs for properties
determined to be productive are transferred to proved oil and gas properties.
8
Other property, plant and equipment additions are recorded at cost and
depreciated on the straight-line method over their estimated service lives,
which range from 3 to 25 years. Maintenance and repair costs are charged to
expense; costs of renewals and betterments are capitalized.
Long-lived assets held and used by the Company are reviewed for impairment
whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. When it is determined that an asset's estimated
future net cash flows will not be sufficient to recover its carrying amount, an
impairment charge is recorded to reduce the carrying amount for that asset to
its estimated fair value. Impairment assessments for proved oil and gas
properties are made on a field-by-field basis. Charges for such impairments,
which are included in DD&A expense, totaled $26,029,000 in 2001 (see Note 9).
Gas services asset impairments of $10,762,000 were recorded in 2000 (see
Note 9).
Environmental expenditures. Liabilities for environmental expenditures are
recognized when it is probable that obligations have been incurred in amounts
that are material and reasonably estimable.
Statements of Cash Flows. Short-term investments with maturities of three months
or less are considered to be cash equivalents. The reported amounts for proceeds
from issuance of debt and debt repayments exclude the impact of borrowings with
initial terms of three months or less. Excluding amounts capitalized of
$7,534,000; $2,948,000 and $2,029,000, respectively, interest paid totaled
$15,504,000; $26,242,000 and $35,182,000 during 2001, 2000 and 1999. Income
taxes paid during those periods totaled $51,834,000; $53,143,000 and $5,591,000.
Other than the asset exchange discussed in Note 3, there were no significant
non-cash investing or financing activities during the three-year period ended
December 31, 2001.
Reclassification. Certain reclassifications of amounts previously reported have
been made to conform to current year reporting.
New accounting standards. The Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for
Asset Retirement Obligations" in June 2001. This statement, which is effective
for fiscal years beginning after June 15, 2002, generally requires the fair
value of an asset retirement obligation to be recognized when an asset is placed
in service.
In August 2001, the Financial Accounting Standards Board issued SFAS No.
144, "Accounting for the Impairment or Disposal of Long-lived Assets", which is
effective for fiscal years beginning after December 15, 2001. This statement
establishes a uniform accounting methodology for long-lived assets to be
disposed of by sale.
The Company's analyses of the impact of these new accounting standards has
not been completed; consequently it is unable to project the effect, if any,
their adoption will have on its financial statements.
9
(2) PROPERTY, PLANT AND EQUIPMENT
The cost and net book value of property, plant and equipment consisted of the
following at December 31, 2001 and 2000 (in thousands):
Cost Net Book Value
------------------------- -------------------------
2001 2000 2001 2000
---------- ---------- ---------- -----------
EXPLORATION AND PRODUCTION
Oil and gas properties................... $2,482,996 $2,034,469 $1,083,846 $ 795,682
Support equipment and facilities......... 56,313 52,632 13,574 12,874
---------- ---------- ---------- -----------
2,539,309 2,087,101 1,097,420 808,556
---------- ---------- ---------- -----------
GAS SERVICES (including investments
in equity partnerships - Note 3)
Natural gas processing................... 283,900 218,583 174,761 117,975
Natural gas gathering.................... 491,783 357,038 300,622 190,569
Other.................................... 83,925 86,771 83,124 86,077
---------- ---------- ---------- -----------
859,608 662,392 558,507 394,621
---------- ---------- ---------- -----------
CORPORATE ............................... 17,056 15,939 2,685 2,828
---------- ---------- ---------- -----------
$3,415,973 $2,765,432 $1,658,612 $1,206,005
========== ========== ========== ==========
(3) UNCONSOLIDATED PARTNERSHIP INVESTMENTS
A summary of the Company's investments in partnerships at December 31, 2001 and
2000 and its equity in their pretax earnings for the years ended December 31,
2001, 2000 and 1999 follows (in thousands):
Investment Equity in Pretax Earnings
Percent ---------------------- -----------------------------------
Owned 2001 2000 2001 2000 1999
----- ---------- ---------- ----------- --------- --------
NATURAL GAS PROCESSING
C&L Processors Partnership (C&L)........... 50(a) $ - $ - $ - $ 740 $ 4,596
U.P. Bryan Plant........................... 45(a) - - - 4,640 7,419
---------- ---------- ----------- --------- --------
- - - 5,380 12,015
---------- ---------- ----------- --------- --------
GAS GATHERING AND MARKETING
Austin Chalk Natural Gas
Marketing Services (Austin Chalk)....... 45(a) - - - 3 899
Ferguson-Burleson County Gas
Gathering System (Ferguson-Burleson).... 45(a) - - - 110 5,223
Louisiana Chalk Gathering System........... 50 3,874 4,217 (343) (11,770)(b) (908)
Others..................................... 329 408 (79) 139 84
---------- ---------- ----------- --------- --------
4,203 4,625 (422) (11,518) 5,298
---------- ---------- ----------- --------- --------
OTHER
Belvieu Environmental Fuels (BEF).......... 33.33 54,426 56,254 5,935 10,438 9,293
Gulf Coast Fractionators................... 38.75 27,357 28,375 2,373 2,641 3,357
---------- ---------- ----------- --------- --------
81,783 84,629 8,308 13,079 12,650
---------- ---------- ----------- --------- --------
$ 85,986 $89,254 $7,886 $ 6,941 $ 29,963
========== ========= ========== ========= ========
------------------------------
(a) Prior to the asset exchange on March 31, 2000.
(b) Includes an asset impairment charge of $10,762 (see Note 9).
10
For the applicable periods, the Company's net investment in each of these
entities is reported as property, plant and equipment in the consolidated
balance sheets and its equity in their pretax earnings is reported as revenues
in the consolidated statements of earnings, each under the gas services caption.
During August 1999, C&L distributed the Jameson gas processing plant and
related facilities to its partners, Conoco and a wholly-owned subsidiary of the
Company. Effective October 1, 1999, the Jameson facilities became wholly owned
when the Company purchased Conoco's 50% interest for approximately $23,900,000.
As a result, these operations were consolidated and ceased being reported as
part of C&L thus reducing C&L's operations to facilities located in Oklahoma.
On March 31, 2000, the Company exchanged its share of the gathering and
processing assets of C&L (non-operated Oklahoma facilities having a net book
value of $26,946,000) for Duke Energy Field Services, Inc.'s share of the
Company operated gathering and processing assets of the U.P. Bryan Plant, Austin
Chalk and Ferguson-Burleson partnerships and $11,666,000 in cash. Each of the
four partnerships distributed all of their operating assets to their partners
prior to the exchange and ceased operations. A gain of $4,884,000 was recognized
in connection with the exchange. The results of the UP Bryan Plant, Austin Chalk
and Ferguson-Burleson partnerships began being reported in the Company's
consolidated results effective April 1, 2000.
Summarized balance sheet information (on a 100% basis) for the
partnerships in which the Company held interests at December 31, 2001 and 2000
follows (in thousands):
2001 2000
--------- ---------
Current assets................................................................ $ 39,198 $ 45,234
Net noncurrent assets......................................................... 223,616 238,546
Current liabilities........................................................... 21,997 31,913
Owners' equity................................................................ 240,817 251,867
For the applicable periods during which the Company held interests in the
above-listed partnerships, summarized earnings information (on a 100% basis) for
those partnerships for the years ended December 31, 2001, 2000 and 1999 follows
(in thousands):
2001 2000 1999
---------- ---------- ----------
Revenues........................................................ $252,234 $382,421 $594,795
Operating earnings.............................................. 21,252 25,685* 70,805
Pretax earnings................................................. 22,488 26,556* 61,542
-----------------------------
* Reduced by an asset impairment charge of $21,524 on the Louisiana Chalk
gathering system.
BEF owns a plant located at Mont Belvieu, Texas with the capacity to
produce up to 17,000 barrels per day of MTBE, a gasoline additive that reduces
emissions. BEF has entered into agreements which require each of the three
partners to provide one-third of the plant's isobutane feedstock and one of the
partners, Sun Company, Inc., to purchase all of its production for a period
extending through September 2004.
11
Various state and federal government legislation requires or proposes to
require that the use of MTBE be phased out. The earliest of these, for which a
deferral is presently being contemplated, would ban the use of MTBE in
California beginning in 2003. While the ultimate timing of any such bans is
uncertain, restrictions on the use of MTBE would significantly impact future
operations of the MTBE plant partially owned by the Company. However, that
facility, which was built in the mid 1990s for approximately $225,000,000, was
originally designed in a manner that allows it to be converted to the production
of other products. It is not possible at this time to determine the ultimate
impact, if any, of this matter on the Company's financial position or results of
future operations.
(4) LONG-TERM DEBT
The Company's outstanding debt consists of unsecured parent company senior
notes, the proceeds of which have been advanced to the operating subsidiaries,
and borrowings under bank revolving credit and money market facilities. A
summary of outstanding debt at December 31, 2001 and 2000 follows (in
thousands):
2001 2000
--------- ----------
Unsecured senior notes
9 1/4%, subsequently repaid on January 15, 2002............................ $ 62,920 $ 64,267
6 3/4%, due February 15, 2004.............................................. 210,855 236,075
$250 million committed bank revolving credit agreement, unsecured............ 150,000 -
Uncommitted money market facilities, at floating interest rates.............. 2,200 -
-------- --------
425,975 300,342
Less - Current maturities.................................................... 62,920 -
-------- --------
$363,055 $300,342
======== ========
The senior notes have no sinking fund requirements and are not redeemable prior
to their respective maturity dates. During August 2000, the Company purchased
$13,925,000 principal amount of the 6 3/4% senior notes at a small discount in
the open market. Borrowings under the Company's $250,000,000 committed bank
revolving credit facility (that was scheduled to terminate in July 2003) were
repaid in January 2002 in connection with Devon's acquisition of the Company as
were money market facility borrowings. Each of those agreements was then
canceled.
The bank revolving credit agreement contained certain restrictions which,
among other things, limited the payment of dividends by requiring consolidated
tangible net worth, as defined, to equal at least $275,000,000 and require the
maintenance of a specified consolidated leverage ratio based on earnings before
interest, taxes and DD&A and excluding extraordinary, unusual, non-recurring and
non-cash charges and credits. Retained earnings available for the payment of
cash dividends totaled $567,244,000 at December 31, 2001. The indenture for the
6 3/4% senior notes limits the incurrence of liens on assets, properties or
systems, restricts the sale or lease of certain assets and limits the right of
the parent company and certain subsidiaries to merge with other companies. In
connection with the acquisition by Devon, a subsidiary of Devon assumed the
Company's obligations under the indenture.
12
(5) INCOME TAXES
Income taxes for the years ended December 31, 2001, 2000 and 1999 consisted of
the following (in thousands):
2001 2000 1999
--------- --------- -------
CURRENT - Federal.......................................... $ 11,318 $ 59,235 $14,782
Prior years' Section 29 tax credits.............. - (12,830) -
State............................................ 90 361 330
--------- --------- -------
11,408 46,766 15,112
--------- --------- -------
DEFERRED - Federal.......................................... 101,880 60,100 18,309
State............................................ (2,149) 238 1,243
Reversals of prior years' state taxes (net
of deferred Federal impact of $3,388 in 2000).. - (6,293) -
--------- --------- -------
99,731 54,045 19,552
--------- --------- -------
$ 111,139 $ 100,811 $34,664
========= ========= =======
During 2000, the Company recorded $12,830,000 of prior years' Section 29 tax
credits applicable to the Boonsville Bend Conglomerate field in North Texas. The
credits were applicable to that field's production for the period February 1,
1992 through December 31, 1999. The Company recognized these credits when the
Federal Energy Regulatory Commission once again began accepting requests for
tight formation gas determinations on October 1, 2000, a certification process
that it had discontinued in the early 1990s.
The prior-year state tax reversal of $6,293,000 in 2000 related to a legal
reorganization of the Company's exploration and production operations, which
allowed certain previously provided deferred state income taxes to be reversed.
Reconciliations between the 35% statutory Federal income tax rate and the
Company's effective rates for income tax provisions (benefits) for 2001, 2000
and 1999 follow:
2001 2000 1999
-------- -------- --------
Statutory Federal income tax rate............................... 35.0% 35.0% 35.0%
State income taxes, net of Federal income tax effect............ (.4) .1 1.0
Federal tax credits under Section 29 of the Internal
Revenue Code for natural gas produced from certain wells...... (1.9) (1.5) (2.7)
Other, net...................................................... .1 - .7
---- ---- ----
32.8 33.6 34.0
Prior years' Section 29 tax credits............................. - (3.6) -
Reversals of prior years' state taxes........................... - (1.8) -
---- ---- ----
32.8% 28.2% 34.0%
==== ==== ====
The tax credit provisions under Section 29 are scheduled to expire at the end of
2002, and it is expected that the amount of the Company's credits for 2002 will
not differ significantly from those applicable to 2001.
13
The principal components of the Company's deferred income tax liability
consisted of the following at December 31, 2001 and 2000 (in thousands):
2001 2000
---------- ----------
Oil and gas acquisition, exploration and development costs
deducted for tax purposes in excess of financial statement DD&A.......... $266,265 $181,730
Depreciation of other property, plant and equipment........................ 60,907 48,917
Accrued compensation and benefits expenses
not yet deductible for tax purposes...................................... (35,848) (36,461)
Unused alternative minimum tax credits .................................... (2,424) -
Other, net................................................................. 7,850 9,733
-------- --------
$296,750 $203,919
======== ========
At December 31, 2001, the Company had $2,424,000 of unused alternative minimum
tax credits that can be carried forward indefinitely. These credits have been
recognized in the calculation of the Company's financial statement income tax
provisions. Accordingly, their future utilization would only reduce the amount
of taxes currently payable, not the financial statement income tax provision.
(6) COMMITMENTS AND CONTINGENCIES
Claims and legal actions. The Company is party to claims and legal actions
arising in the ordinary course of its business and to recurring examinations
performed by the Internal Revenue Service and other regulatory agencies. While
the outcome of such matters cannot be predicted with certainty, management
expects that losses, if any, resulting from their ultimate resolution will not
result in charges that are material to the Company's financial position. It is
possible, however, that charges could be required that would be significant to
the operating results of a particular period.
Leases and contingent liabilities. The Company has various noncancellable
equipment and facility operating lease agreements which provide for aggregate
future payments of approximately $27,300,000. Minimum rentals for each of the
five years subsequent to 2001 total approximately $10,500,000; $10,000,000;
$5,900,000; $600,000 and $100,000. Rental expense for operating leases totaled
approximately $10,400,000; $12,600,000 and $10,800,000 in 2001, 2000 and 1999.
In addition to obligations described elsewhere in these notes, the Company had a
contingent liability of $8,300,000 at December 31, 2001, consisting of a
guarantee of third-party debt.
Environmental regulations. The Company is considered by the EPA to be a
potentially responsible party with respect to two Superfund waste disposal
sites. The only site involving more than minimal potential exposure to the
Company is the Operating Industries, Inc. site located in Monterey Park,
California, where small amounts of non-toxic drilling fluids were deposited from
Company-operated oil and gas wells. Although the Company believes that it should
be exempt from liability with respect to this site, through December 31, 2001 it
had paid and expensed approximately $662,000 of costs. While additional exposure
exists for future cleanup and closure costs of this site, the Company's share of
such costs is not expected to be significant.
The Company continually monitors the many Federal, state and local laws
and regulations relating to the protection of the environment and public health
and believes it is in substantial compliance with such rules.
14
(7) FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2001 and 2000 were as follows (in thousands):
2001 2000
------------------------- -------------------------
Carrying Estimated Carrying Estimated
Amounts Fair Values Amounts Fair Values
------- ----------- ------- -----------
Long-term debt........................................ $425,975 $430,644 $300,342 $299,441
Fair values of the Company's fixed-rate senior notes are based on quoted market
prices. For floating-rate debt, carrying amounts and fair values are assumed to
be equal because of the nature of these obligations. The carrying amounts of
other on-balance-sheet financial instruments approximate their fair values. The
aggregate cost to terminate off-balance-sheet financial instruments is not
significant.
The Company does not hold or issue derivative financial instruments for
trading purposes, and it had no open hedge positions at December 31, 2001 or
2000. As a result, the Company's adoption effective January 1, 2001 of SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," had no
significant impact on its financial statements.
(8) RETIREMENT BENEFITS
Substantially all full-time employees of the Company who meet specified age and
service requirements are covered by a defined benefit retirement plan which is
maintained without cost to the employees. Pension benefits are based on years of
service and average earnings for the three highest consecutive years during the
ten years immediately preceding retirement. The Company's funding policy is to
make contributions to the plan of at least the minimum amounts required by
applicable Federal laws and regulations; no such contributions were made in
2001, 2000 and 1999.
Internal Revenue Service regulations limit the benefits that may be paid
to certain employees under the Company's qualified retirement plan. Nonqualified
plans are maintained to make the basis on which those individuals' retirement
benefits are determined the same as is used for other employees. A Rabbi trust
fund is maintained from which these benefits are paid. That fund's assets -
which under accounting principles generally accepted in the United States must
be reported as an asset of the Company rather than being offset against the
accrued benefit costs - totaled $23,231,000 and $22,503,000 at December 31, 2001
and 2000. These assets are included in Long-term Investments and Other Assets in
the accompanying balance sheets. In connection with Devon's acquisition of the
Company, contributions totaling $13,700,000 were made to the trust in January
2002 using funds advanced by Devon to bring that fund's assets in line with the
estimated projected benefit obligation for nonqualified retirement benefits.
Retirees who reach retirement age while working for the Company and meet
certain other eligibility requirements may elect coverage under the Company's
postretirement medical benefits plan. This plan incorporates a
scheduled-reimbursements methodology under which the Company and providers agree
to specified rates for individual services. The Company has the right to amend
or terminate medical benefits for active employees and retirees or to change the
required level of participant contributions. The cost of providing these
postretirement health care benefits is reduced by available Medicare coverage
and retiree contributions. The plan is unfunded, and benefits are paid as costs
are incurred.
15
The following table provides the indicated information for the years ended
December 31, 2001 and 2000 concerning the Company's retirement plans and its
postretirement medical benefits plan (amounts in thousands):
Qualified Nonqualified Retiree Medical
Retirement Plan Retirement Plans Benefits Plan
---------------------- ---------------------- ----------------------
2001 2000 2001 2000 2001 2000
---------- ---------- ---------- ---------- ---------- ----------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year..... $161,229 $149,815 $24,404 $18,451 $41,724 $29,957
Service cost.............................. 2,982 3,033 182 365 938 517
Interest cost............................. 11,938 11,219 1,787 1,368 3,115 2,233
Benefits paid............................. (10,045) (10,259) (1,978) (1,562) (2,613) (2,804)
Actuarial losses.......................... 9,116 7,421 4,379 5,782 1,436 2,250
Plan amendments........................... 298 - (298) - - 9,171
Contributions by plan participants........ - - - - 691 400
-------- -------- ------- ------- ------- -------
Benefit obligation, end of year........... $175,518 $161,229 $28,476 $24,404 $45,291 $41,724
======== ======== ======= ======= ======= =======
CHANGE IN PLAN ASSETS
Plan assets at fair value,
beginning of year...................... $171,783 $182,534
Actual return on plan assets.............. (14,090) (492)
Benefits paid............................. (10,045) (10,259)
-------- --------
Plan assets at fair value, end of year.... $147,648 $171,783
======== ========
FUNDED STATUS AT YEAR END
Plan assets over (under) benefit
obligation.............................. $(27,870) $ 10,554 $(28,476) $(24,404) $(45,291) $(41,724)
Unrecognized (gains) losses............... 7,841 (31,621) 17,932 14,604 10,536 9,438
Unrecognized prior service cost........... 753 509 (222) 100 4,188 3,985
Unrecognized net transition obligation.... - - - 7 - -
Minimum pension liability adjustment...... - - (17,417) (13,793) - -
-------- -------- -------- -------- -------- --------
Accrued balance sheet liability........... $(19,276) $(20,558) $(28,183) $(23,486) $(30,567) $(28,301)
======== ======== ======== ======== ======== ========
MINIMUM PENSION LIABILITY ADJUSTMENT
Additional minimum liability.............. $ 17,417 $ 13,793
Offsetting intangible asset............... - 107
-------- --------
$ 17,417 $ 13,686
======== ========
The actuarial assumptions used in computing the amounts disclosed herein
included discount rates of 7.15%, 7.50% and 7.75% in 2001, 2000 and 1999, an
expected annual rate of return on plan assets of 9% and age-graded annual salary
increases ranging from 3.5% to 5.5%.
16
Components of financial statement expense for the Company's retirement
plans and its retiree medical benefits plan for the years ended December 31,
2001, 2000 and 1999 were (in thousands):
2001 2000 1999
-------- -------- --------
QUALIFIED RETIREMENT PLAN
Service cost.............................................. $ 2,982 $ 3,033 $ 3,269
Interest cost............................................. 11,938 11,219 11,050
Return on plan assets (expected).......................... (15,009) (15,973) (14,889)
Amortization of prior service cost........................ 55 127 80
Amortization of unrecognized gains........................ (1,248) (3,474) (1,350)
------- -------- -------
Net periodic benefit cost (credit)........................ (1,282) (5,068) (1,840)
Charges for curtailments and special termination benefits. - - 12,687*
------- -------- -------
Financial statement expense (credit)...................... $(1,282) $ (5,068) $10,847
======= ======== =======
NONQUALIFIED RETIREMENT PLANS
Service cost.............................................. $ 183 $ 365 $ 359
Interest cost............................................. 1,787 1,368 1,322
Amortization of prior service cost/transition obligation.. 31 107 225
Amortization of unrecognized losses....................... 1,051 653 837
------- --------- --------
Net periodic benefit cost................................. 3,052 2,493 2,743
Charges for curtailments and special termination benefits. - - 827*
------- -------- -------
Financial statement expense............................... $ 3,052 $ 2,493 $ 3,570
======= ======== ========
RETIREE MEDICAL PLAN
Service cost.............................................. $ 938 $ 517 $ 622
Interest cost............................................. 3,115 2,233 1,875
Amortization of prior service cost credit................. (203) (791) (791)
Amortization of unrecognized losses....................... 338 291 298
------- --------- --------
Net periodic benefit cost................................. 4,188 2,250 2,004
Charges for curtailments and special termination benefits. - - 4,106*
------- --------- --------
Financial statement expense............................... $ 4,188 $ 2,250 $ 6,110
======= ======== ========
---------------
* These charges - which totaled $17,620 - were related to a personnel
reduction program (see Note 9).
The Company's assumed health care cost trend rate equals 8% for 2002,
declines 1% each year to 2005 and remains at 5% thereafter. The health care cost
trend rate assumption has a significant effect on the amount of the retiree
medical benefit obligation and the periodic financial statement expense. An
increase of 1% in the assumed trend rate would have increased the retiree
medical benefit obligation at December 31, 2001 by $6,091,000 and the service
and interest cost components of the 2001 financial statement expense by a total
of $717,000. A decrease of 1% in the trend rate would have reduced these amounts
by $5,073,000 and $537,000, respectively.
The Company maintains a defined contribution plan in which eligible
employees may participate on a voluntary basis. The Company's contributions -
which match each employee's contributions on a dollar-for-dollar basis up to 6%
of eligible compensation - totaled $2,536,000; $2,460,000 and $2,617,000 in
2001, 2000 and 1999.
17
(9) SEGMENT INFORMATION
Selected industry segment data for the years ended December 31, 2001, 2000 and
1999 follows (in thousands):
Inter- Segment Total Capital
Outside segment Operating Operating Expendi- Segment
Revenues Revenues Earnings Earnings DD&A tures(a) Assets
-------- -------- --------- ---------- -------- -------- ------
2001
EXPLORATION AND PRODUCTION
Operations .............................. $ 656,404 $ -- $ 339,651 $ 329,282 $ 165,371 $ 491,865 $1,113,125
Proved property impairment .............. -- -- (26,029) (26,029) 26,029 -- --
---------- ---------- --------- ---------- --------- --------- ----------
656,404 -- 313,622 303,253 191,400 491,865 1,113,125
---------- ---------- --------- ---------- --------- --------- ----------
GAS SERVICES
Natural gas processing .................. 607,747 304,072 35,789 32,306 9,266 67,983 213,748
Natural gas gathering and marketing ..... 546,477 790,873 31,378 27,441 24,945 136,099 376,970
Other ................................... 8,308 -- 7,624 7,300 107 244 83,302
---------- ---------- --------- ---------- --------- --------- ----------
1,162,532 1,094,945 74,791 67,047 34,318 204,326 674,020
---------- ---------- --------- ---------- --------- --------- ----------
CORPORATE ............................... -- -- -- (14,618)(b) 1,354 2,038 124,293
---------- ---------- --------- ---------- --------- --------- ----------
$1,818,936 $1,094,945 $ 388,413 $ 355,682 $ 227,072 $ 698,229 $1,911,438
========== ========== ========= ========== ========= ========= ==========
2000
EXPLORATION AND PRODUCTION
Operations.............................. $ 531,213 $ -- $ 290,385 $ 281,110 $ 118,112 $ 237,811 $ 913,094
Water well litigation provision
reversal ............................. -- -- 1,200 1,200 -- -- --
---------- ---------- --------- ---------- --------- --------- ----------
531,213 -- 291,585 282,310 118,112 237,811 913,094
---------- ---------- --------- ---------- --------- --------- ----------
GAS SERVICES
Natural gas processing .................. 668,321 232,405 84,516 81,439 6,306 46,526 176,639
Natural gas gathering and marketing ..... 454,489 616,026 41,863 38,370 18,454 51.844 272,819
Other ................................... 13,089 -- 12,338 12,076 107 1,780 86,306
Louisiana Chalk asset impairment ........ -- -- (10,762) (10,762) -- -- --
---------- ---------- --------- ---------- --------- --------- ----------
1,135,899 848,431 127,955 121,123 24,867 100,150 535,764
---------- ---------- --------- ---------- --------- --------- ----------
CORPORATE ............................... -- -- -- (27,632)(b) 1,635 1,102 70,907
---------- ---------- --------- ---------- --------- --------- ----------
$1,667,112 $ 848,431 $ 419,540 $ 375,801 $ 144,614 $ 339,063 $1,519,765
========== ========== ========= ========== ========= ========= ==========
1999
EXPLORATION AND PRODUCTION
Operations.............................. $ 254,009 $ -- $ 70,671 $ 60,538 $ 94,667 $ 112,352 $ 717,787
Water well litigation provision
reversals............................. -- -- 14,000 14,000 -- -- --
Personnel reduction program costs ....... -- -- (8,524) (8,524) -- -- --
---------- ---------- --------- ---------- --------- --------- ----------
254,009 -- 76,147 66,014 94,667 112,352 717,787
---------- ---------- --------- ---------- --------- --------- ----------
GAS SERVICES
Natural gas processing .................. 384,587 83,664 47,161 44,293 4,070 23,871 115,300
Natural gas gathering and marketing ..... 226,371 263,874 23,173 19,917 10,341 21,067 156,141
Other ................................... 12,501 -- 11,720 11,389 107 199 86,323
Personnel reduction program costs ....... -- -- (7,128)(c) (7,128) -- -- --
---------- ---------- --------- ---------- --------- --------- ----------
623,459 347,538 74,926 68,471 14,518 45,137 357,764
---------- ---------- --------- ---------- --------- --------- ----------
CORPORATE ............................... -- -- -- (21,038)(b) 2,456 480 88,128
---------- ---------- --------- ---------- --------- --------- ----------
$ 877,468 $ 347,538 $ 151,073 $ 113,447 $ 111,641 $ 157,969 $1,163,679
========== ========== ========= ========== ========= ========= ==========
(a) On accrual basis.
(b) General corporate expenses; 1999 amount includes personnel reduction program
costs of $8,848.
(c) Natural gas processing $1,753; natural gas gathering and marketing $5,375.
The Company's reported business segments are based on the organizational
structure used by management to assess performance and make resource allocation
decisions. The Company's three principal business segments are: exploration and
production, natural gas processing, and natural gas gathering and marketing.
Exploration and production segment operations include the exploration for
18
and development and production of natural gas and oil. Natural gas processing
segment operations include the extraction of natural gas liquids from natural
gas processed at facilities owned by the Company and third parties. The gas
gathering and marketing segment operates Company-owned natural gas gathering
systems and markets natural gas through purchase and resale transactions.
All of the Company's operations are conducted in the United States. Its
revenues are derived principally from uncollateralized sales to customers in the
electrical generation, gas distribution, petrochemical and oil and gas
industries. These industry concentrations have the potential to impact the
Company's exposure to credit risk, either positively or negatively, because
customers may be similarly affected by changes in economic or other conditions.
Intersegment revenues are recorded at prevailing market prices and are
eliminated in consolidation. Gas gathering and marketing sales to a single
customer constituted approximately 21% and 14% of consolidated revenues during
2001 and 2000. Sales to no single customer constituted as much as 10% of
consolidated revenues in 1999.
The reported segment operating earnings amounts represent the operating
earnings of the Company's various industry segments before charges for
administrative, accounting, legal, information systems and other costs that are
managed on a companywide basis. In the reported total operating earnings
disclosures, all general and administrative expenses except for general
corporate expenses incurred in connection with the overall management of the
Company and the operation of the parent company have been allocated to the
industry segments based on their estimated use of these services.
Because of their magnitude and unusual nature, and in accordance with
Accounting Principles Board Opinion No. 30, the items discussed in the following
paragraphs have been reported as separate components of segment operating
earnings.
During September 2001, the Company recorded an impairment charge of
$26,029,000 to reduce the carrying value of a gas field to its estimated fair
value (the present value of its estimated future net cash flows). The impairment
was the result of less than successful drilling results since the affected
property was acquired in 1998 and sharp declines in forecasted natural gas
prices during the third quarter of 2001.
As a result of entering into agreements with insurance carriers
reimbursing the Company for defense costs incurred in connection with previously
resolved litigation, water well litigation provision reversals of $1,200,000 and
$14,000,000, respectively, were recorded in 2000 and 1999.
During December 2000, the Company recorded a $10,762,000 impairment charge
to reduce the carrying value of the 50%-owned Louisiana Chalk pipeline system.
Drilling activity around the system, which had been expected to resume when
industry conditions improved, did not materialize during 2000.
During the first quarter of 1999, the Company completed a personnel
reduction program which reduced its full-time employment level by 235 jobs.
Aggregate pretax costs of this program - including $8,848,000 reported as
general and administrative expense - totaled $24,500,000. Of these costs,
$17,620,000 represented the present value of incremental pension and retiree
medical benefits provided under a voluntary incentive retirement program offered
to 127 employees (114 of whom accepted). Cash costs of severance and other
benefits totaled $6,880,000. The majority of the cash costs were paid by March
31, 1999, and no accrued liability for such costs remained at December 31, 1999.
19
(10) COMMON STOCK AND STOCK OPTIONS
In June 2000, the Company's stockholders voted to combine its two classes of
common stock into a single class of voting common stock by reclassifying each
share of Class B common stock into one share of Class A common stock. Also, the
number of authorized shares of Class A common stock was increased from
100,000,000 to 200,000,000.
The Company's 1995 and 1999 Stock Option Plans authorized the granting of
incentive and nonqualified options to purchase common stock at prices not less
than the market value on the date of grant. The options have maximum terms of 10
years and become exercisable ratably over three-year periods. At December 31,
2001 (prior to closing of the Company's acquisition by Devon), grants covering
an additional 1,074,621 shares could be issued under the plans, and the weighted
average remaining contractual life of stock options outstanding under these
plans was 7.53 years. Previously, options had been granted under the Company's
1979 and 1989 Stock Option Plans, under which no further grants can be made.
Summarized stock option information follows:
1995 and 1999 Plans 1979 and 1989 Plans
------------------------------------------ --------------------------------------------
Options Exercisable Options Exercisable
Options Outstanding at Year End Options Outstanding at Year End
--------------------- ------------------- ------------------- --------------------
Average Average Average Average
Number Price Number Price Number Price Number Price
--------- ------- ------- ------- ------- ------ ------ -----------
At December 31, 1998....... 1,608,488 20.93 911,607 19.72 151,670 19.93 111,670 19.75
March 15, 1999 grants...... 405,400 12.31 -
Exercised.................. - - (10,000) 17.25
Canceled................... (27,525) 19.71 -
--------- ---------
At December 31, 1999....... 1,986,363 19.19 1,331,294 20.45 141,670 20.12 141,670 20.12
May 1, 2000 grants......... 453,100 23.94 -
Exercised.................. (668,490) 19.21 (109,270) 20.05
Canceled................... (9,368) 16.66 -
--------- --------
At December 31, 2000....... 1,761,605 20.41 1,046,460 20.95 32,400 20.36 32,400 20.36
May 9, 2001 grants......... 459,750 54.00 -
Exercised.................. (724,408) 20.63 (32,400) 20.36
Canceled................... (8,835) 25.81 -
--------- --------
At December 31, 2001....... 1,488,112 30.65 602,794 20.18 -
========= ========
Stock options are accounted for under the provisions of APB Opinion No.
25. As a result, the Company does not recognize compensation expense in its
financial statements for outstanding stock options. Had grants under the option
plans been accounted for on the estimated fair-value basis promulgated by SFAS
No. 123, the Company would have recorded additional compensation expense of
$3,178,000; $1,947,000 and $2,159,000 in 2001, 2000 and 1999. On a proforma
basis, earnings from continuing operations would have been reduced by
$2,065,000; $1,266,000 and $1,404,000 in 2001, 2000 and 1999, and basic earnings
per share from continuing operations would have been lowered by 4 cents, 3 cents
and 3 cents, respectively. The additional compensation expense under the
estimated fair-value basis was computed using the Black-Scholes option-pricing
model, expected lives of seven years, annual cash dividends of $.53 per share
(the regular rate paid for the last several years) and the following interest
and volatility rates, which were determined at the dates of the individual
grants:
May 9, May 1, March 5,
2001 2000 1999
-------- -------- ----------
Risk-free interest rate (%)................... 5.20 6.40 5.34
Stock price volatility rate (%)............... 33.59 30.33 29.70
Computed value per option share............... $22.73 $8.93 $3.17
20
(11) INCENTIVE COMPENSATION PLANS
As long-term incentives, the Company periodically issued awards that it calls
"bonus units" under which employees can earn compensation based on increases in
the market price of the Company's stock. Such awards generally were made in lieu
of stock option grants. Upon the redemption of bonus units, grantees receive
gross compensation in amounts equal to the excess of the market price of the
Company's common stock over a floor price (the market price of the stock when
the units were awarded). Up to 1,500,000 units may be granted under the 1997
Bonus Unit Plan. The bonus units generally have ten-year terms and vest in three
equal annual installments. Bonus unit grants under the 1997 Plan were as
follows: 227,950 in December 1997 at a floor price of $26.125; 249,600 in March
1999 at a floor price of $12.3125; 342,800 in May 2000 at a floor price of
$23.9375 and 354,200 in May 2001 at a floor price of $54.00. At December 31,
2001, a total of 861,056 bonus units were outstanding with an average floor
price of $35.1552. Of such units, 195,115 were exercisable at an average floor
price of $23.8255.
Compensation expense is recognized over the applicable vesting terms of
the bonus units in amounts equal to the appreciation in the market price of the
stock over the applicable floor prices. Reversals are recognized to the extent
of previously recorded appreciation in periods when the market price of the
stock declines. Expense accruals for bonus units aggregated $2,192,130;
$21,282,728 and $1,293,000 in 2001, 2000 and 1999.
(12) EARNINGS PER SHARE
The following table reconciles the weighted average shares outstanding used in
the basic and diluted earnings per share computations for the years ended
December 31, 2001, 2000 and 1999 (in thousands):
2001 2000 1999
-------- -------- --------
Used in basic computations...................................... 50,000 49,291 49,117
Dilutive effect of stock options................................ 889 793 106
------ ------ ------
Used in diluted computations.................................... 50,889 50,084 49,223
====== ====== ======
Excluded from these computations because their effect would have been
antidilutive were stock options covering 458,350 shares in 2001 and 1,388,233
shares in 1999. No shares were so excluded in 2000.
(13) SUBSEQUENT EVENT
In a transaction closed on January 24, 2002, Devon Energy Corporation (Devon)
acquired the Company for cash and stock. Shareholders of the Company received
$31.00 cash and 0.585 of a share of Devon common stock for each of the Company's
shares they owned. In connection with the transaction, balances then outstanding
under the Company's committed bank revolving credit and uncommitted money market
facilities were repaid using the proceeds of long-term loans from Devon. Also,
all outstanding stock options and bonus units held by the Company's employees
were vested and converted into options to purchase Devon's common stock and
bonus units redeemable for cash based on the market price of Devon's common
stock. The number of outstanding options and bonus units were multiplied by 1.20
and their exercise/floor prices were divided by 1.20 as part of the conversion.
21
(14) SALE OF OIL AND GAS PROPERTY
During June 1999, the Company sold for cash all its oil and gas properties in
the Hell's Hole and Park Mountain fields in Colorado and Utah, which consisted
of 24,000 net leasehold acres with 36 producing wells and associated pipelines,
gathering systems and production facilities. A pretax gain of $11,527,000
($7,190,000 after tax) was recognized on the sale.
22
Mitchell Energy & Development Corp. and Subsidiaries
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Reserve quantities. Proved reserves are the estimated quantities which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under economic and operating
conditions at each year end. Proved developed reserves are expected to be
recovered from existing wells using existing equipment and operating methods.
Gas and oil reserves included in this Unaudited Supplemental Oil and Gas
Information section are presented in compliance with Statement of Financial
Accounting Standards No. 69 and represent oil and gas reserves derived from the
Company's net mineral interest in producing oil and gas properties.
The amounts reported separately as Plant NGL Reserves represent NGLs that
will be extracted from gas streams contractually committed to company-owned gas
processing plants and are included in order to disclose important and useful
information related to the gas processing segment. The NGL reserves represent
all the NGLs that will be derived by processing natural gas produced from (i)
oil and gas properties owned/operated by the Company and (ii) oil and gas
properties operated by others whose gas production is tied into the gas
processing facilities and contractually purchased, processed and sold by the
Company.
The following tables summarize changes in the Company's natural gas (gas),
crude oil and condensate (oil) and plant NGL reserve quantities during the
indicated years and the proved developed reserve quantities at the dates
indicated:
2001 2000 1999
-------------------------- --------------------------- ---------------------------
Gas Oil Gas Oil Gas Oil
Bcfe * (Bcf) (MMBbls) Bcfe * (Bcf) (MMBbls) Bcfe * (Bcf) (MMBbls)
------- --------- ------- ------- ------- -------- ------- ------- --------
PROVED GAS AND OIL RESERVES
Beginning balance .................... 1,507.7 1,436.0 12.0 1,106.5 1,022.8 14.0 973.6 875.2 16.4
Extensions and discoveries ........... 712.3 694.9 2.9 547.5 539.1 1.4 297.0 289.8 1.2
Production marketed .................. (162.8) (150.8) (2.0) (123.8) (111.8) (2.0) (101.9) (89.3) (2.1)
Production consumed in operations .... (5.3) (5.3) -- (4.7) (4.7) -- (4.5) (4.5) --
Purchases in place ................... 1.6 1.6 -- 4.3 4.3 -- .1 .1 --
Revisions of previous estimates ...... (21.8) (18.2) (.6) (18.2) (11.6) (1.1) (48.0) (39.9) (1.3)
Sales in place ....................... (.1) (.1) -- (3.9) (2.1) (.3) (9.8) (8.6) (.2)
------- ------- ---- ------- ------- ---- ------- ------- ----
Ending balance ....................... 2,031.6 1,958.1 12.3 1,507.7 1,436.0 12.0 1,106.5 1,022.8 14.0
======= ======= ==== ======= ======= ==== ======= ======= ====
-----------------------------------------
* Billion cubic feet of gas equivalent using a 6-to-1 conversion factor for oil.
2001 2000 1999
-------------------------- --------------------------- ---------------------------
Equity Equity Equity
Consol- Partner- Consol- Partner- Consol- Partner-
Total idated ships** Total idated ships** Total idated ships**
------- ------- -------- ------- ------- -------- ------- ------- --------
PROVED PLANT NGL RESERVES (MMBBLS)
Beginning balance................... 175.0 175.0 - 179.1 148.8 30.3 115.8 75.9 39.9
Additions........................... 67.0 67.0 - 42.9 42.9 - 28.2 27.1 1.1
Production.......................... (19.8) (19.8) - (18.2) (17.5) (.7) (16.1) (12.2) (3.9)
Purchase (sale) of plant interests.. - - - (6.2) 11.4 (17.6) 15.2 15.2 -
Transfer of partnership reserves.... - - - - 12.1 (12.1) - 15.2 (15.2)
Revisions of previous estimates..... 6.5 6.5 - (22.6) (22.7) .1 36.0 27.6 8.4
----- ----- ----- ----- ----- ---- ----- ----- -----
Ending balance...................... 228.7 228.7 - 175.0 175.0 - 179.1 148.8 30.3
===== ===== ===== ===== ===== ==== ===== ===== =====
PROVED DEVELOPED RESERVES AT DECEMBER 31 2001 2000 1999 1998
------- ------ ------- -------
Gas (Bcf) ........................................................................... 953.7 737.0 667.1 692.3
===== ===== ===== =====
Oil (MMBbls)......................................................................... 10.2 11.4 13.5 15.2
===== ===== ===== =====
Plant NGLs (MMBbls)
Consolidated ..................................................................... 134.3 115.2 119.3 58.7
Equity partnerships .............................................................. - - 24.4 33.3
----- ----- ----- -----
134.3 115.2 143.7 92.0
===== ===== ===== =====
-------------------------------------------------------------------------------
**Represent the Company's proportional interest in the reserves of partnerships
accounted for using the equity method.
23
Future net cash flows from natural gas and oil reserves. The following tables
set forth estimates of the standardized measure of discounted future net cash
flows from proved gas and oil reserves at December 31, 2001, 2000 and 1999 and a
summary of the changes in those amounts for the years then ended (in millions):
2001 2000 1999
------ ------ ------
STANDARDIZED MEASURE
Future cash inflows...........................$ 5,131 $ 12,945 $ 2,792
Future production costs....................... (1,740) (1,993) (1,207)
Future development costs...................... (951) (564) (248)
Future income taxes........................... (767) (3,547) (374)
Discount - 10% annually....................... (802) (2,885) (385)
-------- ------- ------
$ 871 $ 3,956 $ 578
======== ======== =======
CHANGES IN STANDARDIZED MEASURE
Extensions and discoveries, net of
related costs.............................$ 247 $ 2,105 $ 188
Sales, net of production costs................ (580) (439) (184)
Net changes in prices and production costs.... (5,121) 3,584 340
Accretion of discount......................... 601 74 42
Production rate changes and other............. (117) (53) (28)
Previously estimated development costs
incurred.................................... 260 54 26
Purchases in place............................ 2 20 -
Sales in place................................ - (12) (13)
Revisions of previous quantity estimates...... (26) (68) (63)
Net changes in future income taxes............ 1,649 (1,887) (122)
-------- -------- -------
$ (3,085) $ 3,378 $ 186
======== ======== =======
Development costs for proved undeveloped reserves. The costs of drilling wells
and other development projects whose previously recorded proved undeveloped
reserves were transferred to proved developed during 2001, 2000 and 1999 totaled
$314,788,000; $73,327,000 and $31,506,000, respectively. During the following
three years, the Company estimates that such costs will total approximately
$340,000,000; $414,000,000 and $161,000,000.
Future net cash flows from plant NGL reserves. The following tables set forth
estimates of the standardized measure of discounted future net cash flows from
proved plant NGL reserves at December 31, 2001, 2000 and 1999 and a summary of
the changes in those amounts for the years then ended (in millions):
2000 1999
--------------------------- --------------------------
Equity Equity
Consol- Partner- Consol- Partner-
2001 Total idated ships Total idated ships
-------- ------- ------------------- ------- -------------------
STANDARDIZED MEASURE
Future cash inflows........................ $2,845 $5,533 $5,533 $ - $2,976 $ 2,508 $ 468
Future production costs.................... (2,249) (4,026) (4,026) - (2,281) (1,978) (303)
Future income taxes............................ (167) (505) (505) - (228) (168) (60)
Discount - 10% annually........................ (176) (430) (430) - (202) (153) (49)
------ ------ ------- ----- ------ ------- -----
$ 253 $ 572 $ 572 $ - $ 265 $ 209 $ 56
====== ======= ======= ===== ====== ======= ======
CHANGES IN STANDARDIZED MEASURE
Additions, net of related costs................$ 101 $ 210 $ 210 $ - $ 57 $ 54 $ 3
Sales, net of production costs................. (55) (91) (85) (6) 139 83 56
Net changes in prices and costs................ (658) 480 480 - (45) (30) (15)
Accretion of discount.......................... 86 29 29 - 10 6 4
Purchase/sale of plant interests............... - (51) (4) (47) 30 30 -
Transfer of partnership reserves............... - - 37 (37) - 30 (30)
Revisions of previous quantity estimates....... 10 (111) (111) - 80 55 25
Other.......................................... 3 7 7 - 9 5 4
Net changes in future income taxes............. 194 (166) (200) 34 (94) (70) (24)
------ ------ ------- ----- ------ ------- -----
$ (319) $ 307 $ 363 $ (56) $ 186 $ 163 $ 23
====== ======= ======= ===== ====== ======= ======
24
The natural gas quantities reported as gas and oil reserves represent wet gas
volumes, including quantities that will be converted to NGLs by processing. As
it relates to NGLs to be extracted in processing, the gas and oil future net
cash flows include only the leasehold reimbursements for such NGLs; the other
cash flows (amounts in excess of the leasehold reimbursements) associated with
NGLs to be extracted from the Company's wet gas reserves are included in plant
NGL amounts since those cash flows are attributable to the Company's gas
processing plants.
The future net cash flows from plant NGL reserves represent the net
amounts to be derived from gas plant ownership through natural gas purchase and
processing agreements. The Company's gas processing affiliate purchases raw
natural gas production (including all the liquefiable hydrocarbons contained
therein) from producers (both the Company's exploration and production affiliate
and third parties) during the term of the purchase and processing agreements.
The processing affiliate takes title to the wet gas (including the entrained
NGLs) and then processes the gas for the extraction of the NGLs. Generally,
under the purchase and processing agreements, the producer is paid for the NGLs
associated with its gas under one of two methods. Under one method,
reimbursements to the producer are based on the value of the reduction in the
heating content (measured in BTUs) of the gas that is attributable to the
removal of the NGLs from the gas. This method is sometimes referred to as a "Btu
purchase contract" or a "keep whole contract". Under the other method, which is
called a "percent of proceeds contract", the producer is paid based on a
percentage of the value of NGLs extracted. Regardless of the payment method,
settlements to producers are in cash, not product, and title to 100% of the NGLs
is assigned to the gas processing affiliate, which bears the risks and rewards
of ownership. Such reimbursements - including amounts attributable to the
Company's oil and gas leasehold interests that are included in oil and gas
future net cash flows - are deducted as production costs in determining future
net cash flows from plant NGLs.
Under the gas purchase and processing agreements, the Company's gas
processing affiliate is generally obligated to gather and compresses the gas
from the point of delivery to a central processing plant, to hydrate the gas,
and, if necessary, treat the gas for the removal of contaminants such as carbon
dioxide and hydrogen sulfide and process the gas for the extraction of NGLs.
After the NGLs are removed, the gas processing affiliate compresses the residue
natural gas coming out of the plant and markets the residue gas. The NGLs
extracted at the plant are a raw mixture of ethane, propane, isobutane, normal
butane and natural gasoline which is then separated into individual purity
products at an on-site fractionator or sent via a third-party-owned pipeline to
a large central fractionator and then sold to wholesale and industrial
customers.
Of the total remaining natural gas reserves at December 31, 2001, an
estimated 1,172.1 Bcf will be processed at Company plants, including 398.1 Bcf
of 2001's natural gas reserve additions from extensions and discoveries. It is
estimated that 246.0 Bcf of such reserves and 86.5 Bcf of such reserve additions
will be converted by processing into 104.9 MMBbls and 38.9 MMBbls of plant NGLs,
respectively.
Because of the volatility inherent in prices for natural gas, oil and NGLs
and costs to develop reserves, future cash flow estimates such as those included
herein can change dramatically over even short periods of time. Future cash
flows from plant NGL reserves can also be significantly impacted by changes in
the spread between NGL prices and natural gas costs. Except where otherwise
specified by contractual agreement, future cash inflows are estimated using
year-end prices. Future production and development cost estimates are based on
economic conditions at the respective year ends. Future income taxes are
computed by applying applicable statutory tax rates to the difference between
the estimated future net revenues and the tax basis of proved oil and gas
properties after considering tax credit carryforwards, estimated future
percentage depletion deductions and energy tax credits.
25
Reserve estimates are subject to numerous uncertainties inherent in
estimating quantities of proved reserves and in the projection of future rates
of production and the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of subsequent drilling, testing
and production may cause either upward or downward revisions of previous
estimates. Further, the volumes considered to be commercially recoverable
fluctuate with changes in prices and operating costs. Because of the
aforementioned factors, reserve estimates are generally less precise than other
financial statement disclosures.
Discounted future cash flow estimates such as those shown herein are not
intended to represent estimates of the fair market value of oil and gas
properties. Estimates of fair market value also should consider probable
reserves, anticipated future oil and gas prices and interest rates, changes in
development and production costs and risks associated with future production.
Because of these and other considerations, any estimate of fair market value is
necessarily subjective and imprecise.
Gas and oil related costs and operating results. The following tables set forth
capitalized costs at December 31, 2001, 2000 and 1999 and costs incurred and
operating results for oil and gas producing activities for the years then ended
(in thousands):
2001 2000 1999
----------- ------------ -------------
CAPITALIZED COSTS
Oil and gas properties............................................. $ 2,482,996 $ 2,034,469 $ 1,881,846
Support equipment and facilities................................... 56,313 52,632 50,138
Accumulated depreciation, depletion and amortization............... (1,441,889) (1,278,545) (1,231,047)
----------- ----------- -----------
Net capitalized costs.............................................. $ 1,097,420 $ 808,556 $ 700,937
=========== =========== ===========
COSTS INCURRED (including exploration expenses and
exploratory well impairments of $18,611; $12,028 and $9,022)
Property acquisitions
Unproved........................................................ $ 20,085 $ 16,916 $ 6,450
Proved.......................................................... 5,931 1,565 -
Exploration........................................................ 24,927 15,309 9,646
Development........................................................ 445,949 208,510 101,589
----------- ----------- -----------
Costs incurred..................................................... $ 496,892 $ 242,300 $ 117,685
=========== =========== ===========
OPERATING RESULTS (before charges for
general and administrative and interest expense)
Production revenues................................................ $ 654,905 $ 530,085 $ 252,899
Other revenues..................................................... 1,499 1,143 1,462
----------- ----------- -----------
656,404 531,228 254,361
Less - Production costs
Operating expenses....................................... 76,613 62,316 52,044
Production taxes......................................... 41,659 28,520 16,371
Depreciation, depletion and amortization
(including proved-property impairments of $26,029 in 2001) 191,400 118,112 94,667
Exploration expenses........................................ 8,561 7,216 6,062
Exploratory well impairments................................ 10,050 4,812 2,960
Other operating costs....................................... 14,499 19,852 11,234
----------- ----------- -----------
Segment operating earnings......................................... 313,622 290,400 71,023
Income taxes....................................................... 101,266 77,032 23,009
----------- ----------- -----------
$ 212,356 $ 213,368 $ 48,014
=========== =========== ===========
26
UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION
The following unaudited pro forma combined financial information relates to
the merger between Devon and Mitchell, whereby on January 24, 2002, Devon
acquired all of Mitchell's outstanding common shares with 0.585 shares of Devon
common stock plus $31 per Mitchell common share in cash. The unaudited pro forma
combined financial information also includes the effects of Devon's October 15,
2001 acquisition of Anderson Exploration Ltd. ("Anderson") for approximately
$3.5 billion. The unaudited pro forma combined financial information includes a
balance sheet as of December 31, 2001, which assumes the acquisition of Mitchell
occurred on that date. The unaudited pro forma combined financial information
also includes a statement of operations for the year ended December 31, 2001,
which assumes the acquisitions of Mitchell and Anderson occurred on January 1,
2001.
This pro forma information is based on the historical financial statements
of Devon, Mitchell and Anderson. The pro forma information is based on the
estimates and assumptions set forth in the notes to such information. The pro
forma information is being furnished solely for information purposes and,
therefore, is not necessarily indicative of the results of operations or
financial position that might have been achieved for the dates or periods
indicated, nor is it necessarily indicative of the results of operations or
financial position that may occur in the future.
Anderson's historical financial information is prepared in accordance with
accounting standards generally accepted in Canada, and is presented in Canadian
dollars. Also, Anderson's fiscal year ended on September 30, as opposed to
Devon's year-end of December 31. For purposes of providing the pro forma effect
of the Anderson acquisition on Devon's 2001 results of operations, the following
adjustments were made to Anderson's historical financial data:
- Anderson's historical results for the year ended September 30, 2001 were
converted to results for the nine months ended September 30, 2001. This
conversion was done by subtracting Anderson's historical interim results
for the three months ended December 31, 2000.
- Anderson's results of operations for the nine months ended September 30,
2001, were converted to accounting principles generally accepted in the
United States, including the full cost method of accounting for oil and
gas properties. Such information was also converted to U.S. dollars using
the appropriate exchange rates.
The unaudited pro forma combined financial information was prepared based
on the following:
- Devon uses the full cost method of accounting for its oil and gas
activities, while Mitchell used the successful efforts method. Pro forma
adjustments have been made to estimate the effect of converting
Mitchell's successful efforts method to Devon's full cost method.
- Devon has accounted for the merger and the Anderson acquisition using the
purchase method of accounting.
- The unaudited pro forma balance sheet has been prepared as if the merger
occurred on December 31, 2001. The unaudited pro forma statement of
operations has been prepared as if the merger and the Anderson
acquisition occurred on January 1, 2001.
- In the year ended December 31, 2001, Devon recognized a $49.5 million
after-tax gain from the cumulative effect of a change in accounting
principle. This related to Devon's adoption, as of January 1, 2001, of a
new accounting principle related to accounting for derivative financial
instruments. The $49.5 million gain is not included in the unaudited pro
forma combined statements of operations for the nine months ended
September 30, 2001.
- There is no adjustment to the historical data for annual cost savings of
approximately $20 million and $25 million that Devon expects to result
from the elimination of duplicate expenses after the merger and the
Anderson acquisition, respectively.
27
No pro forma adjustments have been made with respect to the following
unusual items. These items are reflected in the historical results of Devon,
Anderson or Mitchell, as applicable, and should be considered when making
period-to-period comparisons:
- On February 12, 2001, Anderson acquired all of the outstanding shares of
Numac Energy Inc. The unaudited pro forma combined statement of
operations does not include any results from Numac's operations prior to
February 12, 2001.
- During 2001, Devon elected to discontinue operations in Malaysia, Qatar,
Thailand and on certain properties in Brazil. Accordingly, during 2001,
Devon recorded an $87.9 million charge associated with the impairment of
those properties. The after-tax effect of this reduction was $68.8
million.
- During 2001, Devon reduced the carrying value of its oil and gas
properties by $915.7 million due to the full cost ceiling limitations.
The after-tax effect of this reduction was $556.5 million.
- 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 statement of operations for the year
ended December 31, 2001 includes $5.6 million of expenses related to
these plans. After taxes, these plans had the effect of decreasing
unaudited pro forma net earnings in 2001 by $3.2 million. Devon acquired
all outstanding rights as part of the Anderson acquisition. Accordingly,
these rights will not affect the combined company's net earnings
subsequent to the closing of the Anderson acquisition.
- Mitchell had incentive 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 year 2001 include $2.2 million of expense related to
these plans. After taxes, these plans had the effect of decreasing
unaudited pro forma net earnings in 2001 by $1.4 million. Devon will not
issue such bonus units after the merger.
- Devon's historical results of operations for the year 2001 include $33.8
million of amortization expense for goodwill related to previous mergers.
As of January 1, 2002, in accordance with new accounting pronouncements
recently issued, such goodwill will cease to be amortized and, 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 merger and the Anderson acquisition.
28
UNAUDITED PRO FORMA BALANCE SHEET
AS OF DECEMBER 31, 2001
MITCHELL
PRO FORMA COMBINED
DEVON MITCHELL ADJUSTMENTS COMPANY
HISTORICAL HISTORICAL (NOTE 3) PRO FORMA
----------- ---------- ----------- -----------
(IN THOUSANDS)
ASSETS:
Current assets........................... $ 1,081,272 $ 195,119 $ -- $ 1,276,391
Property and equipment, net.............. 9,028,425 1,658,612 1,496,063(a) 12,026,315
(156,785)(d)
Investment in common stock of
ChevronTexaco Corporation.............. 635,553 -- -- 635,553
Goodwill, net............................ 2,205,844 -- 1,388,393(a) 3,594,237
Fair value of derivative instruments..... 30,582 -- -- 30,582
Other assets............................. 202,154 57,707 (385)(a) 271,180
11,704(c)
----------- ---------- ---------- -----------
Total assets................... $13,183,830 $1,911,438 $2,738,990 $17,834,258
=========== ========== ========== ===========
LIABILITIES:
Current liabilities...................... $ 918,971 $ 307,357 $ 88,726(a) $ 1,315,054
Debentures exchangeable into shares of
ChevronTexaco Corporation common
stock.................................. 648,653 -- -- 648,653
Other long-term debt..................... 5,939,781 363,055 1,567,143(c) 7,881,683
11,704(c)
Other long-term liabilities.............. 229,491 101,257 (20,760)(a) 309,988
Fair value of derivative instruments..... 45,573 -- -- 45,573
Deferred income taxes.................... 2,141,874 296,750 559,701(a) 2,943,450
(54,875)(d)
STOCKHOLDERS' EQUITY:
Preferred stock.......................... 1,500 -- -- 1,500
Common stock............................. 12,989 5,386 2,957(a) 15,946
(5,386)(b)
Additional paid-in capital............... 3,610,484 155,464 1,529,323(a) 5,139,807
(155,464)(b)
Retained earnings (accumulated
deficit)............................... (147,017) 766,379 (766,379)(b) (248,927)
Accumulated other comprehensive loss..... (27,782) (11,321) 11,321(b) (27,782)
Treasury stock........................... (190,387) (72,889) 72,889(b) (190,387)
Other.................................... (300) -- -- (300)
----------- ---------- ---------- -----------
Total stockholders' equity..... 3,259,487 843,019 590,904 4,689,857
----------- ---------- ---------- -----------
Total liabilities and
stockholders' equity......... $13,183,830 $1,911,438 $2,738,990 $17,834,258
=========== ========== ========== ===========
29
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2001
DEVON
PRO FORMA MITCHELL MITCHELL
AFTER ANDERSON HISTORICAL PRO FORMA COMBINED
ACQUISITION RECLASSIFIED ADJUSTMENTS COMPANY
(NOTES 1 AND 8) (NOTE 6) (NOTE 3) PRO FORMA
--------------- ------------ ----------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
REVENUE:
Oil sales................................ $1,184,387 $ 48,011 $ -- $1,232,398
Gas sales................................ 2,627,362 517,260 -- 3,144,622
NGL sales................................ 218,259 89,634 -- 307,893
Marketing and midstream revenue.......... 75,977 1,162,532 -- 1,238,509
Other revenue............................ 70,692 28 -- 70,720
---------- ---------- --------- ----------
Total revenue.................. 4,176,677 1,817,465 -- 5,994,142
---------- ---------- --------- ----------
COSTS AND EXPENSES:
Lease operating expenses................. 708,517 60,460 -- 768,977
Transportation costs..................... 122,254 33,143 -- 155,397
Production taxes......................... 121,393 27,614 -- 149,007
Exploration expenses..................... -- 18,611 (18,611)(g) --
Marketing and midstream costs and
expenses............................... 49,689 1,034,898 -- 1,084,587
Depreciation, depletion and amortization
of property and equipment.............. 1,163,558 227,072 12,695(e) 1,403,325
Amortization of goodwill................. 33,846 -- -- 33,846
General and administrative expenses...... 148,597 61,543 (8,443)(g) 201,697
Expenses related to previous mergers..... 1,332 -- -- 1,332
Interest expense......................... 446,173 15,186 45,600(f) 506,959
Deferred effect of changes in foreign
currency exchange rate on subsidiary's
long-term debt......................... 21,266 -- -- 21,266
Change in fair value of derivative
instruments............................ 15,576 -- -- 15,576
Reduction of carrying value of oil and
gas properties......................... 1,003,611 -- 156,785(h) 1,160,396
---------- ---------- --------- ----------
Total costs and expenses....... 3,835,812 1,478,527 188,026 5,502,365
---------- ---------- --------- ----------
Earnings before income tax expense....... 340,865 338,938 (188,026) 491,777
INCOME TAX EXPENSE:
Current.................................. 83,412 11,408 (17,328)(i) 77,492
Deferred................................. 48,210 99,731 (49,849)(i) 98,092
---------- ---------- --------- ----------
Total income tax expense....... 131,622 111,139 (67,177) 175,584
---------- ---------- --------- ----------
Net earnings............................. 209,243 227,799 (120,849) 316,193
Preferred stock dividends................ 9,735 -- -- 9,735
---------- ---------- --------- ----------
Net earnings applicable to common
stockholders........................... $ 199,508 $ 227,799 $(120,849) $ 306,458
========== ========== ========= ==========
Net earnings per average common share
outstanding:
Basic.................................. $ 1.56 $ 4.56 $ 1.95
Diluted................................ 1.54 4.48 1.93
Weighted average common shares
outstanding:
Basic.................................. 127,712 50,000 156,962
Diluted................................ 133,865 50,889 163,634
30
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION
DECEMBER 31, 2001
1. BASIS OF PRESENTATION
The accompanying unaudited pro forma balance sheet and statements of
operations present the pro forma effects of Devon's January 24, 2002, merger
with Mitchell. On October 15, 2001, Devon completed its acquisition of Anderson.
Devon paid approximately $3.5 billion to acquire all of Anderson's outstanding
common shares and to pay for the intrinsic value of Anderson's outstanding
options and appreciation rights. The accompanying unaudited pro forma financial
statements present the effect of the Mitchell merger on Devon's financial
position and results of operations, assuming that the Anderson acquisition had
occurred on January 1, 2001. See Note 8 for the 2001 unaudited pro forma
statement of operations that combines, on a pro forma basis, the results of
operations of Devon and Anderson.
2. METHOD OF ACCOUNTING FOR THE MERGER
Devon has accounted for the merger using the purchase method of accounting
for business combinations. Accordingly, Mitchell's assets acquired and
liabilities assumed by Devon were revalued and recorded at their estimated "fair
values." In the merger, Devon paid $31.00 in cash and issued 0.585 of a share of
Devon common stock for each outstanding share of Mitchell common stock. On a pro
forma basis, assuming that the merger had occurred on December 31, 2001, this
would have resulted in Devon paying approximately $1.6 billion in cash and
issuing approximately 29.6 million shares of its common stock to Mitchell
stockholders.
The purchase price of Mitchell's net assets acquired was based on the total
value of the cash paid and the Devon common stock issued to the Mitchell
stockholders. The value of the Devon common stock issued was based on the
average closing price of Devon's common stock for a period of three days before
and after the public announcement of the merger. This average closing price
equaled $50.95 per share.
31
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
3. PRO FORMA ADJUSTMENTS RELATED TO THE MERGER
The unaudited pro forma balance sheet includes the following adjustments:
(a) This entry adjusts the historical book values of Mitchell's assets
and liabilities to their estimated fair values as of December 31, 2001. The
calculation of the total purchase price and the preliminary allocation to
assets and liabilities are shown below.
(IN THOUSANDS,
EXCEPT FOR SHARE
PRICE)
Calculation and preliminary allocation of purchase price:
Shares of Devon common stock to be issued to Mitchell
stockholders........................................... 29,574
Average Devon stock price................................. $ 50.95
----------
Fair value of common stock to be issued................... 1,506,795
Cash to be paid to Mitchell stockholders, calculated at
$31 per outstanding common share of Mitchell........... 1,567,143
----------
Fair value of Devon common stock and cash to be issued to
Mitchell stockholders.................................. 3,073,938
Plus estimated merger costs to be incurred................ 90,000
Plus fair value of Mitchell employee stock options to be
assumed by Devon....................................... 25,485
----------
Total purchase price.............................. 3,189,423
Plus fair value of liabilities to be assumed by Devon:
Current liabilities....................................... 306,083
Long-term debt............................................ 363,055
Other long-term liabilities............................... 80,497
Deferred income taxes..................................... 859,384
----------
Total purchase price plus liabilities assumed..... $4,798,442
==========
Fair value of assets to be acquired by Devon:
Current assets............................................ $ 195,119
Proved oil and gas properties............................. 1,520,886
Unproved oil and gas properties........................... 639,170
Marketing and midstream facilities and equipment.......... 1,000,000
Other property and equipment.............................. 3,000
Other assets.............................................. 57,322
Goodwill.................................................. 1,382,945
----------
Total fair value of assets to be acquired......... $4,798,442
==========
The total purchase price includes the value of the cash and Devon common
stock to be issued to Mitchell stockholders. The total purchase price also
includes:
- $90.0 million of estimated merger costs. These costs include investment
banking expenses, severance, legal and accounting fees, printing expenses
and other merger-related costs. These costs have been added to current
liabilities in the unaudited pro forma balance sheet.
- $25.5 million of Devon employee stock options to be issued in exchange
for existing vested Mitchell employee stock options. The value of these
options is added to additional paid-in capital in the unaudited pro forma
balance sheet.
The purchase price allocation is preliminary and is subject to change as
the final tax bases and fair values are determined of the assets acquired and
liabilities assumed.
32
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
(b) This adjustment includes a $5.4 million reduction of common stock,
a $155.5 million reduction of additional paid-in capital, a $766.4 million
reduction of retained earnings, an $11.3 million reduction of accumulated
other comprehensive loss and a $72.9 million reduction of treasury stock.
These adjustments eliminate the historical book value of Mitchell's
stockholders' equity.
(c) This adjustment increases long-term debt by $1.6 billion to
include the long-term debt that Devon would have incurred on December 31,
2001, to fund the cash portion of the merger consideration. The debt was
borrowed under Devon's $3 billion, variable interest rate, five year credit
facility entered into on October 12, 2001. Debt under this facility matures
between 2003 and 2005. The adjustment also includes $11.7 million of costs
estimated to be incurred in connection with issuing this debt.
(d) This adjustment is for the additional reduction of carrying value
of oil and gas properties that would have been recorded as of December 31,
2001, for the merger. This adjustment equals the difference between the
fair value of the oil and gas properties at year-end 2001 and the related
ceiling allowed under the full cost method of accounting.
The unaudited pro forma statement of operations includes the following
adjustments:
(e) This adjustment revises historical depreciation, depletion and
amortization to reflect the adjustment of Mitchell's assets from historical
book value to fair value and a change to the full cost accounting method
from the successful efforts method. For Mitchell's midstream assets
acquired, pro forma depreciation expense was calculated using estimated
useful lives of approximately 15 years. For Mitchell's oil and gas
producing properties acquired, pro forma depreciation, depletion and
amortization expense was calculated using the equivalent
units-of-production method. Mitchell's proved oil and gas reserves, divided
by its annualized production for 2001, yields an estimated reserve life of
14 years. The increase in depreciation, depletion and amortization of $2.7
million is net of the reversal of an impairment charge of $26.0 million
recognized by Mitchell under the successful efforts method.
(f) This adjustment increases interest expense due to the $1.6 billion
of additional long-term debt. This adjustment has been calculated using an
estimated interest rate of 2.89%, plus the amortization of estimated
financing costs to be incurred, on the variable rate debt. This assumed
interest rate is based on the terms of Devon's $3 billion credit facility.
The actual rate will vary with changes in market rates. A change in the
interest rate of 0.125% would change the combined company pro forma
interest expense by $2.7 million. This change includes the amount related
to the debt borrowed under the $3 billion credit facility to fund a portion
of the Anderson acquisition as described in Note 8.
(g) This adjustment eliminates historical amounts recognized by
Mitchell under the successful efforts accounting method that are not
recognized as expenses under the full cost accounting method. Included in
this adjustment are costs incurred by Mitchell related to its property
exploration activities such as exploratory dry holes and geological and
geophysical costs that are expensed as incurred under the successful
efforts method followed by Mitchell, but are capitalized under the full
cost method followed by Devon. Also included in this adjustment are general
and administrative expenses incurred by Mitchell which were directly
identified with its acquisition, exploration and development activities
undertaken for its own account. These costs are expensed as incurred under
the successful efforts method, but are capitalized under the full cost
method.
(h) See note (d) above.
(i) This adjustment records the income tax impact of all pro forma
adjustments at an effective tax rate of approximately 36%.
33
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
4. COMMON SHARES OUTSTANDING
Net earnings per average share outstanding have been calculated based on
the pro forma weighted average number of shares outstanding as follows:
YEAR ENDED
DECEMBER 31, 2001
-----------------
(IN THOUSANDS)
Basic:
Devon's weighted average common shares outstanding........ 127,712
New Devon shares to be issued to Mitchell stockholders.... 29,250
-------
Pro forma weighted average Devon shares outstanding....... 156,962
=======
Diluted:
Devon's weighted average common shares outstanding........ 133,864
New Devon shares to be issued to Mitchell stockholders.... 29,770
-------
Pro forma weighted average Devon shares outstanding....... 163,634
=======
Pro forma shares of Devon common stock outstanding at December 31, 2001,
assuming the merger occurred on that date, are as follows:
(IN THOUSANDS)
Devon's common shares outstanding...................... 126,132
New Devon shares to be issued to Mitchell
stockholders......................................... 29,574
-------
Pro forma Devon common shares outstanding.............. 155,706
=======
5. GOODWILL
The preliminary pro forma allocation of the purchase price includes
approximately $1.4 billion of goodwill. In July 2001, the Financial Accounting
Standards Board issued Statement No. 141, "Business Combinations," and Statement
No. 142, "Goodwill and Other Intangible Assets." As a result of these two recent
pronouncements, goodwill recorded in connection with business combinations
completed after June 30, 2001 (including the merger) will not be amortized but,
instead, will be tested for impairment at least annually. Accordingly, the
accompanying unaudited pro forma statements of operations include no
amortization of the goodwill to be recorded in the merger.
Statement No. 142 was adopted by Devon as of January 1, 2002. Until that
date, goodwill recognized from business combinations completed prior to June 30,
2001 must continue to be amortized. Therefore, Devon's historical goodwill
amortization related to previous mergers has not been reversed in the
accompanying unaudited pro forma statements of operations. As of January 1,
2002, goodwill related to these previous mergers will no longer be amortized
but, instead, will be tested for impairment at least annually. The accompanying
unaudited pro forma statement of operations for the year ended December 31, 2001
includes amortization of goodwill related to previous mergers of $33.8 million.
6. DEVON AND MITCHELL HISTORICAL AND RECLASSIFIED BALANCES
Devon and Mitchell record certain revenue and expenses differently in their
respective consolidated financial statements. To make the unaudited pro forma
financial information consistent, certain of Devon's and Mitchell's balances
have been reclassified to conform presentation.
Devon's historical balances for other revenue have been reclassified to
include separate line items for marketing and midstream revenue and marketing
and midstream costs and expenses to conform to Mitchell's presentation and
Devon's presentation subsequent to the merger.
34
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
The following tables present Mitchell's balances as presented in its
historical financial statements and the reclassified balances that are included
in the accompanying unaudited pro forma statement of operations.
YEAR ENDED DECEMBER 31, 2001
---------------------------------------------
MITCHELL
MITCHELL HISTORICAL
HISTORICAL RECLASSIFICATIONS RECLASSIFIED
---------- ----------------- ------------
(IN THOUSANDS)
REVENUE:
Exploration and production.................................. $ 656,404 $(656,404) $ --
Oil sales................................................... -- 48,011 48,011
Gas sales................................................... -- 517,260 517,260
NGL sales................................................... -- 89,634 89,634
Marketing and midstream revenue............................. 1,162,532 -- 1,162,532
Other revenue............................................... -- 28 28
---------- --------- ----------
Total revenue..................................... 1,818,936 (1,471) 1,817,465
---------- --------- ----------
COSTS AND EXPENSES:
Exploration and production.................................. 342,782 (342,782) --
Lease operating expenses.................................... -- 60,460 60,460
Transportation costs........................................ -- 33,143 33,143
Production taxes............................................ -- 27,614 27,614
Exploration expenses........................................ -- 18,611 18,611
Marketing and midstream..................................... 1,087,741 (52,843) 1,034,898
Depreciation, depletion and amortization of property and
equipment................................................. -- 227,072 227,072
General and administrative expenses......................... 32,731 28,812 61,543
Interest expense............................................ 22,720 (7,534) 15,186
Other (income) expense, net................................. (5,976) 5,976 --
---------- --------- ----------
Total costs and expenses.......................... 1,479,998 (1,471) 1,478,527
---------- --------- ----------
Earnings before income taxes................................ 338,938 -- 338,938
Income tax expense.......................................... 111,139 -- 111,139
---------- --------- ----------
Net earnings...................................... $ 227,799 $ -- $ 227,799
========== ========= ==========
35
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
7. MARKETING AND MIDSTREAM INFORMATION
The following table provides certain information relating to the unaudited
pro forma marketing and midstream revenues and costs and expenses for the year
ended December 31, 2001.
YEAR ENDED
DECEMBER 31,
2001
--------------
(IN THOUSANDS)
MARKETING AND MIDSTREAM REVENUE:
Gas processing operations:
Percentage of proceeds NGL volumes (MBbls)............. 6,870
Keep whole NGL volumes (MBbls)......................... 8,263
----------
Total NGL volumes................................. 15,133
Average NGL price per barrel........................... $ 18.22
----------
NGL revenue............................................ 275,775
NGL marketing and other revenue........................ 389,555
----------
Total gas processing revenue...................... 665,330
Natural gas gathering and marketing revenue............... 568,336
Other gas services revenue................................ 4,843
----------
Total gas services revenue........................ $1,238,509
==========
MARKETING AND MIDSTREAM COSTS AND EXPENSES:
Gas processing operations:
Percentage of proceeds payments........................ $ 61,781
Keep whole gas purchased............................... 127,525
Other NGL costs........................................ 39,223
----------
Total NGL costs................................... 228,529
NGL marketing and other costs and expenses............. 367,642
----------
Total gas processing costs and expenses........... 596,171
Natural gas gathering and marketing costs and expenses.... 487,839
Other gas services costs and expenses..................... 577
----------
Total gas services costs and expenses............. $1,084,587
==========
Natural gas gathering and marketing margins (natural gas gathering and
marketing revenue less natural gas gathering and marketing costs and expenses)
were unusually high in the year 2001. After the merger, Devon expects the
combined company's natural gas gathering and marketing margin to approximate
between $30 million and $40 million per year.
The above table contains the terms "percentage of proceeds" and "keep
whole." These terms refer to two different types of contracts involving
processing natural gas. Under a percentage of proceeds contract, the buyer and
seller share in the net proceeds from the sale of all NGLs and residue gas
allocated to the seller after reductions for fuel use, line loss and processing
shrink. Residue gas refers to that portion of the seller's natural gas that
remains after processing.
A keep whole contract allows the seller to sell 100% of the BTUs it
delivers at the wellhead even though the natural gas is being processed to
extract NGLs. To do this, the buyer must deliver to the seller an equivalent
amount of BTUs as were extracted from the gas at the processing plant or
reimburse the seller the value of the gas extracted. This is referred to as
"keep whole gas" in the above table. The seller receives its allocation of
residue gas plus the keep whole gas from the buyer, so that the seller's total
wellhead BTUs are "kept whole". In this type of agreement, the buyer bears the
processing risk, in that the total revenues received from the NGLs sold must
exceed the cost of the keep whole gas for the buyer to have a positive margin.
36
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
8. UNAUDITED PRO FORMA EFFECT OF ANDERSON ACQUISITION
The following presents the pro forma effect of the October 15, 2001,
Anderson acquisition on Devon's historical statement of operations for the year
ended December 31, 2001. The column headed "Devon Historical Reclassified"
includes the effect of the Anderson acquisition from October 15, 2001, through
December 31, 2001. The column headed "Anderson Historical Reclassified U.S.
GAAP" includes Anderson's results of operations for the nine months ended
September 30, 2001. The column headed "Pro Forma Adjustments" includes
adjustment (e) which accounts for Anderson's results of operations for the first
fourteen days of October 2001. The column headed "Devon Pro Forma After Anderson
Acquisition" represents Devon's pro forma results for 2001 assuming the Anderson
Acquisition had occurred on January 1, 2001.
Anderson's historical amounts presented in the following statement have
been converted to accounting principles generally accepted in the United States
and to U.S. dollars. For information on such conversions, see Note 9.
Devon has accounted for the Anderson acquisition using the purchase method
of accounting for business combinations. Accordingly, Anderson's assets acquired
and liabilities assumed by Devon were revalued and recorded at their estimated
"fair values." In the Anderson acquisition, Devon paid C$40 per share for each
outstanding common share, including associated rights, of Anderson. This
resulted in Devon paying approximately $3.4 billion in cash to Anderson
stockholders, as well as an additional $0.1 billion of cash paid to Anderson
employees for the intrinsic value of outstanding stock options and appreciation
rights. These U.S. dollar amounts are based on the October 15, 2001 exchange
rate of C$1.00 to U.S.$0.6419.
37
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
DEVON-ANDERSON
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2001
ANDERSON DEVON
DEVON HISTORICAL PRO FORMA
HISTORICAL RECLASSIFIED AFTER
RECLASSIFIED U.S. GAAP PRO FORMA ANDERSON
(NOTE 6) (NOTE 9) ADJUSTMENTS ACQUISITION
------------ ------------ ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
REVENUE:
Oil sales.................................. $ 957,666 $218,733 $ 7,988(e) $1,184,387
Gas sales.................................. 1,889,788 720,241 17,333(e) 2,627,362
NGL sales.................................. 132,571 82,754 2,934(e) 218,259
Marketing and midstream revenue............ 69,764 5,950 263(e) 75,977
Other...................................... 72,016 (1,248) (243)(d) 70,692
167(e)
---------- -------- --------- ----------
Total revenues..................... 3,121,805 1,026,430 28,442 4,176,677
---------- -------- --------- ----------
COSTS AND EXPENSES:
Lease operating expenses................... 531,025 169,191 8,301(e) 708,517
Transportation costs....................... 82,819 37,444 1,991(e) 122,254
Production taxes........................... 116,788 4,459 146(e) 121,393
Marketing and midstream costs and
expenses................................ 46,595 3,094 -- 49,689
Depreciation, depletion and amortization of
property and equipment.................. 876,250 257,482 15,239(a) 1,163,558
14,587(e)
Amortization of goodwill................... 33,846 -- -- 33,846
General and administrative expenses........ 111,068 36,350 1,179(e) 148,597
Expenses related to previous mergers....... 1,332 -- -- 1,332
Interest expense........................... 220,137 49,780 181,909(b) 446,173
(17,021)(c)
11,368(e)
Deferred effect of changes in foreign
currency exchange rate on subsidiary's
long-term debt.......................... 12,588 14,719 (6,041)(e) 21,266
Change in fair value of derivative
instruments............................. 1,924 13,652 -- 15,576
Reduction of carrying value of oil and gas
properties.............................. 1,003,611 -- -- 1,003,611
---------- -------- --------- ----------
Total costs and expenses........... 3,037,983 586,171 211,658 3,835,812
---------- -------- --------- ----------
Earnings before income tax expense........... 83,822 440,259 (183,216) 340,865
INCOME TAX EXPENSE:
Current.................................... 70,852 13,201 (641)(f) 83,412
Deferred................................... (40,623) 155,932 (67,099)(f) 48,210
---------- -------- --------- ----------
Total income tax expense........... 30,229 169,133 (67,740)(f) 131,622
---------- -------- --------- ----------
Net earnings before cumulative effect of
change in accounting principle............. 53,593 271,126 (115,476) 209,243
Preferred stock dividends.................... 9,735 -- -- 9,735
---------- -------- --------- ----------
Net earnings applicable to common
stockholders............................... $ 43,858 $271,126 $(115,476) $ 199,508
========== ======== ========= ==========
Net earnings per average common share
outstanding:
Basic...................................... $ 0.34 $ 1.56
Diluted.................................... 0.34 1.54
Weighted average common shares outstanding:
Basic...................................... 127,712 127,712
Diluted.................................... 133,864 133,864
38
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
PRO FORMA ADJUSTMENTS RELATED TO THE ANDERSON ACQUISITION
The Devon-Anderson unaudited pro forma statement of operations included in
this note includes the following adjustments:
(a) This adjustment increases historical depreciation, depletion and
amortization expense to reflect the adjustment of Anderson's assets from
historical book value to fair value. For Anderson's oil and gas producing
properties acquired, pro forma depreciation, depletion and amortization
expense was calculated using the equivalent units-of-production method.
Anderson's proved oil and gas reserves, divided by its annualized
production, yields an estimated reserve life of ten years.
(b) This adjustment increases interest expense due to the $3.5 billion
of long-term debt that Devon would have incurred at January 1, 2001, to
fund the Anderson acquisition. This adjustment has been calculated using an
average interest rate of 7.4% on the $3.0 billion of fixed rate debt, and
an estimated rate of 3.17%, plus the amortization of estimated financing
costs, on the $0.5 billion of variable rate debt. The assumed interest rate
on the variable rate debt is based on the terms of Devon's $3 billion
credit facility. The actual rates on this variable rate debt will vary with
changes in market rates. A change in the interest rate of 0.125% would
change the pro forma interest expense by $0.8 million.
(c) This adjustment reduces interest expense to reflect the repayment
of Anderson's bank debt with debt borrowed under Devon's $3 billion credit
facility that bears a lower interest rate, plus a decrease in interest
expense related to the effect of valuing Anderson's fixed-rate debt at the
estimated fair value of such debt. The adjustment relating to the repayment
of Anderson's bank debt reduced interest expense for the first nine months
of 2001 by $15.2 million. The adjustment relating to recording Anderson's
fixed-rate debt at fair value decreased interest expense for the first nine
months of 2001 by $1.8 million.
(d) This adjustment reduces the Alberta Royalty Tax Credit as a result
of the acquisition of Anderson.
(e) This adjustment includes Anderson's revenues and expenses for the
first 14 days of October 2001 prior to its acquisition by Devon on October
15, 2001.
(f) This adjustment records the income tax impact of all pro forma
adjustments at an effective tax rate of approximately 37%. The rate
includes the effect of a change in Canadian tax rates enacted during the
second quarter of 2001. Excluding the retroactive effect of this rate
change, the rate applied to the 2001 pro forma adjustments would have been
40%.
GOODWILL
The October 15, 2001, allocation of the purchase price for the Anderson
acquisition included approximately $2.0 billion of goodwill. In July 2001, the
Financial Accounting Standards Board issued Statement No. 141, "Business
Combinations," and Statement No. 142, "Goodwill and Other Intangible Assets." As
a result of these two recent pronouncements, goodwill recorded in connection
with business combinations completed after June 30, 2001 (including the Anderson
acquisition) will not be amortized but, instead, will be tested for impairment
at least annually. Accordingly, the Devon-Anderson unaudited pro forma statement
of operations included in this note includes no amortization of the goodwill
recorded in the Anderson acquisition.
Statement No. 142 was adopted by Devon as of January 1, 2002. Until that
date, goodwill recognized from business combinations completed prior to June 30,
2001 must continue to be amortized. Therefore, Devon's historical goodwill
related to previous mergers has not been reversed in the Devon-Anderson
unaudited pro forma statement of operations included in this note. As of January
1, 2002, goodwill related to these previous mergers will no longer be amortized
but, instead, will be tested for impairment at least
39
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
annually. The Devon-Anderson unaudited pro forma statement of operations
included in this note for the year ended December 31, 2001 includes amortization
of goodwill related to previous mergers of $33.8 million.
9. CONVERSION OF ANDERSON'S HISTORICAL FINANCIAL STATEMENTS
Anderson prepared its historical financial statements based on a fiscal
year of September 30. To conform to Devon's year-end of December 31, Anderson's
historical results for the year ended September 30, 2001 were converted to
results for the nine months ended September 30, 2001. This conversion was done
by subtracting Anderson's historical interim results for the three months ended
December 31, 2000.
Anderson prepared its historical financial statements using accounting
principles generally accepted in Canada ("Canadian GAAP") and Canadian dollars.
The following tables provide information relating to the conversion of
Anderson's historical financial statements to those prepared using accounting
principles generally accepted in the United States ("U.S. GAAP") and U.S.
dollars.
40
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
ANDERSON UNAUDITED U.S. GAAP STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2001
U.S. GAAP
ANDERSON AND OTHER ANDERSON CONVERTED
HISTORICAL ADJUSTMENTS U.S. GAAP TO
C$ C$ C$ U.S.$
----------- ----------- ----------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
REVENUE:
Oil sales............................. C$ 397,832 C$ (61,371)(a) C$ 336,461 $218,733
Gas sales............................. 1,396,195 (288,302)(a) 1,107,893 720,241
NGL sales............................. 155,668 (28,373)(a) 127,295 82,754
Less royalties........................ (448,920) 448,920(a) -- --
Gas services revenue.................. -- 9,152(a) 9,152 5,950
Other................................. 4,499 (6,418)(a) (1,919) (1,248)
----------- ---------- ----------- --------
Total revenues................ 1,505,274 73,608 1,578,882 1,026,430
----------- ---------- ----------- --------
COSTS AND EXPENSES:
Lease operating expenses.............. 255,861 4,393(a) 260,254 169,191
Transportation costs.................. -- 57,597(a) 57,597 37,444
Production taxes...................... -- 6,859(a) 6,859 4,459
Gas services costs and expenses....... -- 4,759(a) 4,759 3,094
Depreciation, depletion and
amortization of property and
equipment.......................... 421,165 (44,200)(b) 396,065 257,482
19,100(d)
General and administrative expenses... 55,915 -- 55,915 36,350
Interest expense...................... 81,114 (4,541)(c) 76,573 49,780
Deferred effect of changes in foreign
currency exchange rate on long-term
debt............................... -- 22,641(c) 22,641 14,719
Change in fair value of derivative
instruments........................ -- 21,000 (e) 21,000 13,652
----------- ---------- ----------- --------
Total costs and expenses...... 814,055 87,608 901,663 586,171
----------- ---------- ----------- --------
Earnings before income tax expense...... 691,219 (14,000) 677,219 440,259
INCOME TAX EXPENSE:
Current............................... 20,306 -- 20,306 13,201
Deferred.............................. 242,609 (2,750)(f) 239,859 155,932
----------- ---------- ----------- --------
Total income tax expense...... 262,915 (2,750) 260,165 169,133
----------- ---------- ----------- --------
Net earnings............................ C$ 428,304 C$ (11,250) C$ 417,054 $271,126
=========== ========== =========== ========
Net earnings per average common share
outstanding:
Basic................................. C$ 3.26 C$ 3.18 $ 2.07
Diluted............................... 3.19 3.11 2.02
Weighted average common shares
outstanding:
Basic................................. 131,241 131,241 131,241
Diluted............................... 134,187 134,187 134,187
41
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
The following adjustments convert Anderson's Canadian GAAP statements of
operating results to U.S. GAAP statements of operating results:
(a) This adjustment (1) allocates oil, gas and NGL royalty payments to
oil, gas and NGL revenues in accordance with U.S. GAAP; (2) reclassifies
third party processing revenues from lease operating expenses to gas
services revenues and expenses, and freehold mineral taxes from royalties
to production taxes, to conform to Devon's presentation; and (3)
reclassifies transportation costs which are netted against oil, gas and NGL
sales in Anderson's historical results as expenses in accordance with U.S.
GAAP.
(b) This adjustment records the impact of a lower depreciation,
depletion and amortization rate for U.S. GAAP as a result of a reduction in
carrying value of oil and gas properties which Anderson would have
recognized in 1998 due to a U.S. full cost ceiling limitation.
(c) This adjustment recognizes foreign exchange losses on long-term
debt in accordance with U.S. GAAP.
(d) This adjustment reflects additional depreciation, depletion and
amortization resulting from the accounting for the initial adoption of the
liability method of accounting for income taxes as an adjustment to
property and equipment.
(e) This adjustment records the impact of changes in the fair value of
derivative instruments that do not qualify as hedges under U.S. GAAP.
(f) This adjustment records the income tax impact of all the U.S. GAAP
adjustments described above.
For the U.S. GAAP statement of operations for the nine months ended
September 30, 2001, Canadian dollars were converted to U.S. dollars using the
exchange rate of $0.6501. Such rate is the average of the month end exchange
rates for the nine-month period.
10. 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 "cost 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. 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 write down otherwise indicated
at the end of the quarter is not required to be recorded. A write down 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 December 31, 2001,
the combined company's pro forma domestic, Canadian and Egyptian costs to be
recovered exceeded the related ceiling values by $383.3 million, $252.0 million
and $23.1 million, respectively. These after-tax amounts would have resulted in
pro forma pre-tax reductions of the carrying values of the combined company's
domestic and Canadian oil and gas properties of $605.5 million, $434.1 million,
and $32.9 million, respectively, in the fourth quarter of 2001.
42
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
The combined company pro forma results for 2001 include a reduction of the
carrying value of oil and gas properties related to Devon's decision to
discontinue its operations in Malaysia, Qatar, Thailand and on certain
properties in Brazil. After meeting the drilling and capital commitments on
these properties, Devon determined that the properties did not meet Devon's
internal criteria to justify further investment. Accordingly, during the first
nine months of 2001, Devon recorded a pre-tax charge on $87.9 million ($68.8
million after-tax) associated with the impairment of these international
properties.
11. SUPPLEMENTAL PRO FORMA INFORMATION ON OIL AND GAS OPERATIONS
The following pro forma supplemental information regarding oil and gas
operations is presented pursuant to the disclosure requirements of Statement of
Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing
Activities."
Pro Forma Costs Incurred
The following tables reflect the costs incurred in oil and gas property
acquisition, exploration and development activities of Devon, Mitchell and the
combined company on a pro forma basis, for the year ended December 31, 2001. The
"Devon Pro Forma" amounts assume the Anderson acquisition had occurred on
December 31, 2000.
DEVON COMBINED DEVON COMBINED
PRO FORMA MITCHELL COMPANY PRO FORMA MITCHELL COMPANY
--------- -------- -------- --------- -------- --------
(IN MILLIONS)
TOTAL DOMESTIC
------------------------------- -------------------------------
Property acquisition costs:
Proved...................................... $1,169 $ 6 $1,175 $371 $ 6 $ 377
Unproved.................................... 429 20 449 185 20 205
Exploration costs............................. 621 25 646 166 25 191
Development costs............................. 1,216 446 1,662 726 446 1,172
CANADA INTERNATIONAL
------------------------------- -------------------------------
Property acquisition costs:
Proved...................................... $ 736 $ -- $ 736 $ 62 $ -- $ 62
Unproved.................................... 243 -- 243 1 -- 1
Exploration costs............................. 391 -- 391 64 -- 64
Development costs............................. 406 -- 406 84 -- 84
43
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
Pro Forma Quantities of Oil and Gas Reserves
The following tables set forth the changes in the net quantities of oil,
natural gas and NGL reserves of Devon, Mitchell and the combined company on a
pro forma basis, for the year ended December 31, 2001. The "Devon Pro Forma"
amounts assume the Anderson acquisition had occurred on December 31, 2000.
DEVON COMBINED DEVON COMBINED
PRO FORMA MITCHELL COMPANY PRO FORMA MITCHELL COMPANY
--------- -------- -------- --------- -------- --------
TOTAL OIL -- MMBBLS DOMESTIC OIL -- MMBBLS
------------------------------- -------------------------------
Proved reserves as of December 31, 2000....... 560 12 572 226 12 238
Revisions of estimates...................... (8) (2) (10) (25) (2) (27)
Extensions and discoveries.................. 38 3 41 12 3 15
Purchase of reserves........................ 75 -- 75 15 -- 15
Production.................................. (55) (1) (56) (26) (1) (27)
Sale of reserves............................ (24) -- (24) (11) -- (11)
------ ------ ------ ------ ------ ------
Proved reserves as of December 31, 2001....... 586 12 598 191 12 203
====== ====== ====== ====== ====== ======
Proved developed reserves as of:
December 31, 2000........................... 332 11 343 192 11 203
December 31, 2001........................... 324 10 334 167 10 177
CANADA OIL -- MMBBLS INTERNATIONAL OIL -- MMBBLS
------------------------------- -------------------------------
Proved reserves as of December 31, 2000....... 137 -- 137 197 -- 197
Revisions of estimates...................... 6 -- 6 11 -- 11
Extensions and discoveries.................. 12 -- 12 14 -- 14
Purchase of reserves........................ 42 -- 42 18 -- 18
Production.................................. (19) -- (19) (10) -- (10)
Sale of reserves............................ (12) -- (12) (1) -- (1)
------ ------ ------ ------ ------ ------
Proved reserves as of December 31, 2001....... 166 -- 166 229 -- 229
====== ====== ====== ====== ====== ======
Proved developed reserves as of:
December 31, 2000........................... 101 -- 101 39 -- 39
December 31, 2001........................... 124 -- 124 33 -- 33
TOTAL GAS -- MMCF DOMESTIC GAS -- MMCF
------------------------------- -------------------------------
Proved reserves as of December 31, 2000....... 5,248 1,263 6,511 2,521 1,263 3,784
Revisions of estimates...................... (321) (7) (328) (262) (7) (269)
Extensions and discoveries.................. 854 598 1,452 360 598 958
Purchase of reserves........................ 387 2 389 170 2 172
Production.................................. (673) (137) (810) (376) (137) (513)
Sale of reserves............................ (18) -- (18) (14) -- (14)
------ ------ ------ ------ ------ ------
Proved reserves as of December 31, 2001....... 5,477 1,719 7,196 2,399 1,719 4,118
====== ====== ====== ====== ====== ======
Proved developed reserves as of:
December 31, 2000........................... 3,845 659 4,504 2,087 659 2,746
December 31, 2001........................... 3,948 887 4,835 1,988 887 2,875
44
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
DEVON COMBINED DEVON COMBINED
PRO FORMA MITCHELL COMPANY PRO FORMA MITCHELL COMPANY
--------- -------- -------- --------- -------- --------
CANADA GAS -- MMCF INTERNATIONAL GAS -- MMCF
------------------------------- -------------------------------
Proved reserves as of December 31, 2000....... 2,314 -- 2,314 413 -- 413
Revisions of estimates...................... (28) -- (28) (31) -- (31)
Extensions and discoveries.................. 414 -- 414 80 -- 80
Purchase of reserves........................ 217 -- 217 -- -- --
Production.................................. (288) -- (288) (9) -- (9)
Sale of reserves............................ (4) -- (4) -- -- --
------ ------ ------ ------ ------ ------
Proved reserves as of December 31, 2001....... 2,625 -- 2,625 453 -- 453
====== ====== ====== ====== ====== ======
Proved developed reserves as of:
December 31, 2000........................... 1,722 -- 1,722 36 -- 36
December 31, 2001........................... 1,923 -- 1,923 37 -- 37
TOTAL NGLS -- MBBLS DOMESTIC NGLS -- MBBLS
------------------------------- -------------------------------
Proved reserves as of December 31, 2000....... 109 59 168 46 59 105
Revisions of estimates...................... 3 6 9 7 6 13
Extensions and discoveries.................. 14 31 45 5 31 36
Purchase of reserves........................ 7 -- 7 -- -- --
Production.................................. (12) (6) (18) (6) (6) (12)
Sale of reserves............................ -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Proved reserves as of December 31, 2001....... 121 90 211 52 90 142
====== ====== ====== ====== ====== ======
Proved developed reserves as of:
December 31, 2000........................... 80 27 107 42 27 69
December 31, 2001........................... 88 42 130 48 42 90
CANADA NGLS -- MBBLS INTERNATIONAL NGLS -- MBBLS
------------------------------- -------------------------------
Proved reserves as of December 31, 2000....... 51 -- 51 12 -- 12
Revisions of estimates...................... (3) -- (3) (1) -- (1)
Extensions and discoveries.................. 7 -- 7 2 -- 2
Purchase of reserves........................ 7 -- 7 -- -- --
Production.................................. (6) -- (6) -- -- --
Sale of reserves............................ -- -- -- -- -- --
------ ------ ------ ------ ------ ------
Proved reserves as of December 31, 2001....... 56 -- 56 13 -- 13
====== ====== ====== ====== ====== ======
Proved developed reserves as of:
December 31, 2000........................... 38 -- 38 -- -- --
December 31, 2001........................... 40 -- 40 -- -- --
45
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
Pro Forma Standardized Measure of Discounted Future Net Cash Flows
The following tables set forth the standardized measure of discounted
future net cash flows relating to proved oil, natural gas and NGL reserves for
Devon, Mitchell and the combined company on a pro forma basis, as of December
31, 2001.
COMBINED COMBINED
DEVON MITCHELL COMPANY DEVON MITCHELL COMPANY
------- -------- -------- ------- -------- --------
(IN MILLIONS)
TOTAL DOMESTIC
----------------------------- -----------------------------
Future cash inflows........................ $23,790 $ 5,131 $28,921 $ 9,861 $ 5,131 $14,992
Future costs:
Development.............................. (2,228) (951) (3,179) (793) (951) (1,744)
Production............................... (8,424) (1,740) (10,164) (3,774) (1,740) (5,514)
Future income tax expense.................. (3,403) (767) (4,170) (759) (767) (1,526)
------- ------- -------- ------- ------- -------
Future net cash flows...................... 9,735 1,673 11,408 4,535 1,673 6,208
10% discount to reflect timing of cash
flows.................................... (4,421) (802) (5,223) (1,734) (802) (2,536)
------- ------- -------- ------- ------- -------
Standardized measure of discounted future
net cash flows........................... $ 5,314 $ 871 $ 6,185 $ 2,801 $ 871 $ 3,672
======= ======= ======== ======= ======= =======
CANADA INTERNATIONAL
----------------------------- -----------------------------
Future cash inflows........................ $ 9,011 $ -- $ 9,011 $ 4,918 $ -- $ 4,918
Future costs:
Development.............................. (922) -- (922) (513) -- (513)
Production............................... (3,292) -- (3,292) (1,358) -- (1,358)
Future income tax expense.................. (2,006) -- (2,006) (638) -- (638)
------- ------- -------- ------- ------- -------
Future net cash flows...................... 2,791 -- 2,791 2,409 -- 2,409
10% discount to reflect timing of cash
flows.................................... (1,195) -- (1,195) (1,492) -- (1,492)
------- ------- -------- ------- ------- -------
Standardized measure of discounted future
net cash flows........................... $ 1,596 $ -- $ 1,596 $ 917 $ -- $ 917
======= ======= ======== ======= ======= =======
Future cash inflows are computed by applying year-end prices to the
year-end quantities of proved reserves, except in those instances where fixed
and determinable price changes are provided by contractual arrangements in
existence at year-end. These year-end prices are adjusted for transportation and
other charges, and for geographic differentials. The December 31, 2001 NYMEX oil
price and Henry Hub gas price, upon which the combined company's actual net
prices were based before relevant adjustments, were $19.84 per barrel and $2.65
per Mcf, respectively.
46
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION -- (CONTINUED)
Pro Forma Changes Relating to the Standardized Measure of Discounted Future
Net Cash Flows
The following table includes the components of the changes in the
standardized measure of discounted future net cash flows of Devon, Mitchell and
the combined company on a pro forma basis, for the year ended December 31, 2001.
The "Devon Pro Forma" amounts assume the Anderson acquisition had occurred on
December 31, 2000.
DEVON COMBINED
PRO FORMA MITCHELL COMPANY
--------- -------- --------
(IN MILLIONS)
Beginning balance........................................... $ 17,114 $ 3,956 $ 21,070
Sales of oil, gas and NGLs, net of production costs......... (3,078) (534) (3,612)
Net changes in prices and production costs.................. (17,766) (5,121) (22,887)
Extensions, discoveries, and improved recovery, net of
future development costs.................................. 925 247 1,172
Purchase of reserves, net of future development costs....... 681 2 683
Development costs incurred during the period which reduced
future development costs.................................. 430 260 690
Revisions of quantity estimates............................. (481) (26) (507)
Sales of reserves in place.................................. (158) -- (158)
Accretion of discount....................................... 1,774 601 2,375
Net change in income taxes.................................. 6,594 1,649 8,243
Other, primarily changes in timing.......................... (721) (163) (884)
-------- ------- --------
Ending balance.............................................. $ 5,314 $ 871 $ 6,185
======== ======= ========
47
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 hereunto duly authorized.
DEVON ENERGY CORPORATION
Dated: July 17, 2002 By: /s/ Danny J. Heatly
-------------------------------
Name: Danny J. Heatly
Title: Vice President