Annual Report (Form 10-K), fiscal year 1993

ITEM 1. BUSINESS.
Pogo Producing Company (the 'Company'), incorporated in 1970, is engaged in oil and gas exploration, development and production activities on its properties located offshore in the Gulf of Mexico and onshore in the United States. The Company is also engaged in exploration of its license concession in the Gulf of Thailand, and is evaluating a development program in connection with its recently announced oil and gas discoveries on that concession. The Company has interests in 76 lease blocks offshore Louisiana and Texas, approximately 93,000 gross acres onshore in the United States, approximately 2,635,000 gross acres offshore in the Kingdom of Thailand, and approximately 1,965,000 gross acres in Australia.
DOMESTIC OFFSHORE OPERATIONS
Historically, the Company's interests have been concentrated in the Gulf of Mexico, where approximately 81% of the Company's domestic proved reserves and 68% of its total proved reserves are now located. During 1993, approximately 75% of the Company's natural gas equivalent production was from its domestic offshore properties, contributing approximately 75% of consolidated oil and gas revenues. Four offshore producing areas, Eugene Island, South Marsh Island, Main Pass and East Cameron, account for approximately 52% of the Company's net proved natural gas reserves and approximately 56% of the Company's proved crude oil, condensate and natural gas liquids reserves. Eugene Island is the Company's largest producing area with 1993 average net revenue interest production (net to the Company's interest and net of royalty burdens) of 24 million cubic feet ('MMcf') per day of natural gas and 4,600 barrels ('Bbls') per day of oil, condensate and natural gas liquids. The table in Item 2



ITEM 2. PROPERTIES.
The information appearing in Item 1 of this Annual Report is incorporated herein by reference.
PRINCIPAL PROPERTIES As of January 1, 1994, approximately 81% of the Company's domestic proved oil and gas equivalent reserves and approximately 68% of the Company's total proved oil and gas equivalent reserves were located on properties in the Gulf of Mexico. Five significant producing areas, of which four are located in the Gulf of Mexico and the fifth is located in New Mexico, accounted for approximately 59% of the estimated proved natural gas reserves and approximately 74% of the estimated oil, condensate and natural gas liquids reserves of the Company as of January 1, 1994. These producing areas accounted for approximately 60% of natural gas production and 90% of oil, condensate and natural gas liquids production for 1993. Reserves and production data for the five principal producing areas, as estimated by Ryder Scott, are shown in the following table. No other major producing area accounted for more than 5% of the estimated discounted future net revenues attributable to the Company's estimated proved reserves as of January 1, 1994. However, the Company's Thailand concession, which is currently not a producing property, accounts for approximately 14% of the Company's total estimated net proved reserves of natural gas, approximately 19% of the Company's total estimated net proved reserves of oil, condensate and natural gas liquids and approximately 16% of the Company's total net proved oil and gas equivalent reserves.
Set forth below are descriptions of certain of the Company's significant producing areas. Contained in certain of these descriptions and elsewhere in this Annual Report are production rate test results with regard to certain wells and fields in which the Company has an interest. Such production rate tests, while accurate, are never indicative of actual sustained production rates.
EUGENE ISLAND
The Company's most significant reserves are in the Eugene Island area located off the Louisiana coast in the Gulf of Mexico. The Eugene Island area has been an important part of the Company's operations since the first lease in that area was purchased in 1970 and production began in 1973. The Company currently holds interests in 13 blocks in the Eugene Island area. These comprise eight fields containing 90 gross oil and gas wells producing from multiple reservoirs and horizons.
The Eugene Island Block 330 field is the Company's most significant asset, with 28 productive Pleistocene horizons between 4,000 and 8,000 feet, containing multiple reservoirs. The field, located in 245 feet of water, contains three drilling and production platforms in which the Company holds a 35% working interest, as well as an additional platform in which the Company holds a 30% working interest. There are currently 18 wells producing primarily natural gas and 35 wells producing primarily oil on the block. In 1993, a successful five well drilling program was completed in the field which included one horizontal and four vertical wells. A multi-well program off of the field's 'D' platform commenced in early January 1994. Since initial production in 1973, the Eugene Island
Block 330 field has produced approximately 619 billion cubic feet ('Bcf') of natural gas and 122 million barrels ('MMBbls') of oil and condensate (167 Bcf and 35 MMBbls, attributable to the Company's net revenue interest). Reserves have been added to this field consistently since production commenced. These increases have been derived from new exploratory horizons, infill drilling, field expansions and higher than anticipated recovery efficiencies.
Another significant field to the Company is Eugene Island Block 295. In production since 1973, this block has recorded gross production of over 387 Bcf of natural gas and over 2.9 MMBbls of oil and condensate during its twenty-year life. In August 1993, the Company effected an exchange of working interests in Eugene Island Block 295 with another working interest owner in such block. Pursuant to this exchange, the Company increased its working interest in Eugene Island Block 295 to 100% on 3,125 acres above 3,000 feet, to 20% on 1,875 acres above 3,000 feet and to 20% on all of the block below 3,000 feet. During the fourth quarter of 1993, the Company successfully drilled and completed five horizontal wells to exploit the natural gas potential located in certain shallow reservoirs on this block in an area where it has a 100% working interest. These five wells tested at a gross calculated cumulative daily flow rate of 100 MMcf of natural gas per day, although platform compression capacity and lease burdens dictate that ultimate net production volumes will be substantially less than this amount. The Company completed construction of a production platform over these wells and commenced initial production from the first of these wells in late February 1994.
The Eugene Island 212 field consists of Eugene Island Blocks 211 and 212 and Ship Shoal Block 175. The field contains eight productive horizons which have four oil wells and one natural gas well producing from a platform set in 1985. The Company and its partners drilled a successful infill development well in this field during the second half of 1993.
SOUTH MARSH ISLAND
The Company currently owns five blocks in the South Marsh Island area, located offshore Louisiana. Three of the leases were acquired in 1974, a fourth in 1980 and the most recent in 1992. Three blocks contain a total of five drilling and production platforms. These platforms currently have 44 oil and gas wells producing from Pleistocene age sandstone reservoirs located at depths from 5,000 to 10,000 feet.
The South Marsh Island Block 128 field, in which the Company owns a 16% working interest, comprises South Marsh Island Blocks 125, 127 and 128. This field primarily produces oil, with 36 oil wells and six natural gas wells producing from 20 separate reservoirs. The first four wells in a supplemental five well drilling program in this field were completed in 1993. The current drilling program is based on the ongoing analysis of a 3-D seismic survey in conjunction with a detailed reservoir study of the field.
The Company also owns a 25% working interest in the South Marsh Island Block 160 field which is producing from two oil wells at a depth of approximately 9,700 feet. A single platform was set on this block in 1983. A two-well drilling program in this field is currently being considered as a result of recent analysis of a 3-D seismic survey on the block.
MAIN PASS
The Company's nine blocks in the Main Pass area are located near the mouth of the Mississippi River in the Gulf of Mexico and include leases purchased from 1974 to 1992. The primary drilling objectives in these fields are Pliocene and Miocene sandstone reservoirs with productive formation depths from 5,000 to 12,000 feet. The Company's interests in the Main Pass area include 57 producing oil and gas wells producing from six platforms.
A field including Main Pass Blocks 72, 73 and 72/74 was unitized in 1982 with the Company's working interest at 14%. This field contains 33 oil wells and 11 natural gas wells operated by one of
the Company's joint venture partners. The field is located in 125 feet of water with 38 mapped horizons adjacent to and surrounding a salt dome. These horizons contain over 150 separate reservoirs between 5,000 and 12,000 feet. A successful three-well workover program in this field was completed in 1992. Many of the producing reservoirs in this field have consistently outperformed their initial recovery estimates. Based on the high historical recovery efficiency, it is anticipated that some of the multiple behind pipe reservoirs remaining will also outperform their existing reserve estimates.
Main Pass Block 123 was acquired in the federal lease sale of 1990. Pogo Gulf Coast, for which the Company is the general partner, has a 75% working interest and is the operator on the block. Along with its non-operating joint venture partner, Pogo Gulf Coast drilled two discovery wells on the block in 1993 and is currently planning additional drilling as well as the installation of a production platform in late 1994.
EAST CAMERON
The original lease purchased by the Company and its partners in the East Cameron area off the Texas/Louisiana border in the Gulf of Mexico commenced production in February 1973. Presently, the Company has interests in 4 offshore blocks in this area which contain three fields and 16 producing gas wells.
During 1992, the Company and its partners conducted a 3-D seismic survey of the East Cameron Block 334/335 field area where the Company has a 42% working interest. The Company currently anticipates commencing a multi-well drilling program in this field during the first half of 1994.
NEW MEXICO
The Company considers southeastern New Mexico to be an area of significant growth in both production and reserves as a result of recent exploration and development activities. The Company believes that during the past four years it has been one of the most active companies drilling for oil and natural gas in the southeastern New Mexico (Lea and Eddy Counties) portion of the Permian Basin where the Company has interests in over 50,000 gross acres. The Company's primary drilling objective is the Brushy Canyon (Delaware) formation. Fields in the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of the Permian Basin are generally characterized by production from relatively shallow depths (6,000 to 9,000 feet), multiple producing zones in most wells and relatively high initial rates of production (frequently equaling the top field allowables which range from of 142 Bbls to 230 Bbls per day, depending on the depth of production from the field). The Company has achieved rapid cost recovery with respect to its New Mexico wells drilled to date because of relatively low capital costs and high initial rates of production.
Through December 31, 1993, the Company and its partners had drilled and completed as productive 151 consecutive wells in Lea and Eddy Counties, including, among others, 52 wells in the Sand Dunes field where the Company's working interest ranges from 4% to 89%; 27 wells in the East Loving field where the Company's working interest ranges from 33% to 98%; 43 wells in the Livingston Ridge field where the Company's working interest ranges from 41% to 83%; and 8 wells in the Red Tank field where the Company's working interest ranges from 89% to 100%. The oil fields in this area are generally developed on 40 acre spacings. The Company anticipates drilling many additional locations in these and other fields in southeastern New Mexico during 1994 and in future years.
DOMESTIC OFFSHORE PROPERTIES --
The following is a listing of Pogo's domestic offshore properties as of December 31, 1993.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS.
In 1989, a large number of exploration and production companies, including the Company, were circularized with Special Notice Letters in accordance with CERCLA from the EPA regarding a particular waste disposal site in Louisiana known as the 'Gulf Coast Vacuum Site' utilized by a trucking company. The EPA subsequently developed a list based on its investigation showing the Company bearing an approximate 1.4% responsibility for this site based on the trucking company's shipping records. The Company utilized the trucking company to dispose of salt water produced from a well in which the Company had an interest. The Company, however, believes that none of this salt water was delivered to the Gulf Coast Vacuum Site. In any event, the Company believes that the trucking company shipped only oilfield waste for the Company which is exempt pursuant to CERCLA and, further, that such shipments, if any, were sent to a properly permitted waste disposal site. The Company has learned that the EPA has recently entered a consent decree, the details of which have not been made public, with parties that are believed to be responsible for a majority of the disposal occurring at the site.
The Company is a party to various other legal proceedings consisting of routine litigation incidental to its businesses, but believes that any potential liabilities resulting from these proceedings are adequately covered by insurance or are otherwise immaterial at this time.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.
Not Applicable.
ITEM S-K 401(B). EXECUTIVE OFFICERS OF REGISTRANT.
Executive officers of the Company are appointed annually to serve for the ensuing year or until their successors have been elected or appointed. The executive officers of the Company, their age as of February 1, 1994, and the year each was elected to his present position are as follows:
Prior to assuming their present positions with the Company, the business experience of each executive officer for more than the last five years was as follows: Mr. Van Wagenen was President and
Chief Operating Officer of the Company since 1990, Senior Vice President and General Counsel of the Company since 1986, Vice President and General Counsel of the Company since 1982, and General Counsel of the Company since 1979; Mr. Good was Vice President - Land of the Company since 1988 and Chief Landman of the Company since 1977; Mr. Slack was Regional Manager of Chemical Bank of New York's Southwest Energy and Minerals Division since 1982; Mr. Burbach was Vice President of Norfolk Holding Inc. since 1986 and Exploration Manager for Tricentrol Ltd. Canada and Tricentrol U.S. since 1981; Mr. Cooper was a Division Landman for the Company since 1983 and a Landman for the Company since 1979; Mr. Gold was Manager of Reservoir Engineering for the Company since 1977; Mr. Hart was Controller for the Company since 1977; Mr. Laney was International Exploration Manager for the Company since 1983 and Exploration Coordinator for the Gulf Coast Division of the Company since 1977; Mr. McCoy was Director of Personnel and Administration for the Company since 1978; Mr. McGregor was Manager of Hydrocarbon Sales and Contracts for the Company since 1981; Mr. Shaw was Operations Manager for the Company since 1981; Mr. Manning was an Associate General Counsel for the Company since 1989 and prior thereto was an attorney with the Federal Bureau of Investigation, and Chevron U.S.A., and Assistant to the General Counsel of Primary Fuels, Inc.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS.
The following table shows the range of low and high sales prices of the Company's Common Stock (the 'Common Stock') on the New York Stock Exchange composite tape where the Company's Common Stock trades under the symbol PPP. The Company's Common Stock is also listed on the Pacific Stock Exchange.
The Board of Directors of the Company has not declared cash dividends on the Company's Common Stock since the fourth quarter of 1986, and has no current plans to pay dividends.
Pursuant to various agreements under which the Company has borrowed funds, the Company may not, subject to certain exceptions, pay any dividends on its capital stock or make any other distributions on shares of its capital stock (other than dividends or distributions payable solely in shares of such capital stock) or acquire for value any shares of its capital stock if (after giving effect to the proposed payment, distribution, or acquisition) the aggregate amount of all such payments, distributions or acquisitions on and after a specified date would exceed an amount determined based on the consolidated income or cash flow of the Company and its consolidated subsidiaries from and after such date. As of December 31, 1993, $33,803,000 was available for dividends under the most restrictive of such limitations.
LOW HIGH 1st Quarter------------------------------------- 5 1/8 6 1/2 2nd Quarter------------------------------------- 5 1/8 6 3/8 3rd Quarter------------------------------------- 5 1/2 10 3/8 4th Quarter------------------------------------- 9 3/4 13 7/8 1st Quarter------------------------------------- 9 3/4 17 1/4 2nd Quarter------------------------------------- 16 1/8 21 3rd Quarter------------------------------------- 13 5/8 19 1/8 4th Quarter------------------------------------- 14 3/8 19 3/4
As of February 10, 1994, there were 4,216 holders of record of the Company's Common Stock.
ITEM 7.


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS
The Company reported net income for 1993 of $25,061,000 or $0.76 per share compared to net income for 1992 of $18,495,000 or $0.66 per share and net income for 1991 of $11,658,000 or $0.42 per share. Included in net income for 1991 are extraordinary gains of $1,336,000 or $0.05 per share in connection with purchases at less than face value of the Company's 8% Convertible Subordinated Debentures due 2005 (the 'Convertible Subordinated Debentures'). Earnings per common share are based on the weighted average number of shares of common and common equivalent shares outstanding for 1993 of 32,860,000 compared to 27,929,000 for 1992 and 27,611,000 for 1991. The increases in the weighted average number of common and common equivalent shares outstanding for 1993 primarily related to the issuance of 4,500,000 shares of common stock in December 1992 as set forth in the Consolidated Statements of Shareholders' Equity included in 'Item 8.


ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1993
POGO PRODUCING COMPANY AND SUBSIDIARIES HOUSTON, TEXAS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Pogo Producing Company:
We have audited the accompanying consolidated balance sheets of Pogo Producing Company (a Delaware corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of Pogo's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. 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 Pogo Producing Company and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in Item 14(a)-2 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Houston, Texas February 8, 1994
POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, 1993 1992 1991
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Oil and gas---------------------- $ 136,553 $ 139,128 $ 124,425 Interest on tax refund----------- 2,322 -- -- Gains on sales------------------- 679 1,702 44 Total------------------------ 139,554 140,830 124,469 Operating Costs and Expenses: Lease operating------------------ 26,633 25,842 28,192 General and administrative------- 14,550 13,129 14,555 Exploration---------------------- 2,455 3,102 2,408 Dry hole and impairment---------- 4,690 9,314 4,554 Depreciation, depletion and amortization------------------- 40,693 42,302 37,521 Total------------------------ 89,021 93,689 87,230 Operating Income--------------------- 50,533 47,141 37,239 Interest: Charges-------------------------- (10,956) (19,036) (24,946) Income--------------------------- 14 191 1,686 Capitalized---------------------- 451 391 637 Income Before Taxes and Extraordinary Item--------------------------------- 40,042 28,687 14,616 Income Tax Expense------------------- (14,981) (10,192) (4,294) Income Before Extraordinary Item----- 25,061 18,495 10,322 Extraordinary Gains on Purchase of Debt, net of tax------------------- -- -- 1,336 Net Income--------------------------- $ 25,061 $ 18,495 $ 11,658 Primary and Fully Diluted Earnings per Common Share: Before extraordinary item-------- $0.76 $0.66 $0.37 Extraordinary item--------------- -- -- 0.05 Net income----------------------- $0.76 $0.66 $0.42
The accompanying notes to consolidated financial statements are an integral part hereof.
POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1993 1992 (EXPRESSED IN THOUSANDS)
ASSETS Current Assets: Cash and cash investments-------- $ 6,713 $ 5,037 Accounts receivable-------------- 18,480 22,652 Other receivables---------------- 10,123 4,173 Federal income taxes and interest receivable--------------------- 3,320 -- Inventories---------------------- 1,105 1,383 Other---------------------------- 727 367 Total current assets--------- 40,468 33,612 Property and Equipment: Oil and gas, on the basis of successful efforts accounting Proved properties being amortized------------------ 817,218 869,192 Unproved properties and properties under development, not being amortized------------------ 6,465 5,962 Other, at cost------------------- 6,961 6,851 830,644 882,005 Less -- accumulated depreciation, depletion, and amortization, including $4,452 and $4,032, respectively, applicable to other property----------------- 638,658 717,428 191,986 164,577 Other-------------------------------- 7,320 8,158 $ 239,774 $ 206,347
LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable----------------- $ 8,307 $ 9,899 Other payables------------------- 22,955 5,541 Current portion of long-term debt--------------------------- 4,000 4,000 Current portion of production payment------------------------ -- 10,517 Accrued interest payable--------- 1,202 1,122 Accrued payroll and related benefits----------------------- 1,005 942 Other---------------------------- 122 142 Total current liabilities---- 37,591 32,163 Long-Term Debt----------------------- 130,539 129,260 Production Payment------------------- -- 14,337 Deferred Federal Income Tax---------- 29,724 17,435 Deferred Credits--------------------- 8,117 7,504 Total liabilities------------ 205,971 200,699 Shareholders' Equity: Preferred stock, $1 par; 2,000,000 shares authorized---- -- -- Common stock, $1 par; 43,333,333 shares authorized, 32,449,197 and 32,103,864 shares issued, respectively------------------- 32,449 32,104 Additional capital--------------- 125,919 122,846 Retained earnings (deficit)------ (124,241) (149,302) Treasury stock, at cost---------- (324) -- Total shareholders' equity--------------------- 33,803 5,648 $ 239,774 $ 206,347
The accompanying notes to consolidated financial statements are an integral part hereof.
POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 1993 1992 1991 (EXPRESSED IN THOUSANDS) Cash flows from operating activities: Cash received from customers------- $ 141,012 $ 135,877 $ 125,029 Operating, exploration, and general and administrative expenses paid------------------------------ (45,051) (41,360) (46,746) Interest paid---------------------- (10,912) (21,262) (26,701) Payment of royalties and related interest on FERC Order 94-A refunds--------------------------- -- (4,872) -- Federal income taxes paid---------- (2,800) (1,500) (2,900) Federal income taxes and interest received-------------------------- -- -- 30,836 Settlement of natural gas sales contract-------------------------- -- -- 3,300 Proceeds of life insurance policy---------------------------- -- -- 2,568 Other------------------------------ 895 828 2,974 Net cash provided by operating activities------- 83,144 67,711 88,360 Cash flows from investing activities: Capital expenditures--------------- (62,353) (30,304) (51,284) Purchase of proved reserves-------- -- (8,924) (5,077) Proceeds from the sale of property and tubular stock----------------- 2,713 4,017 2,150 Net cash used in investing activities----------------- (59,640) (35,211) (54,211) Cash flows from financing activities: Net borrowings (payments) under revolving credit agreements------- 8,000 (1,000) 17,000 Principal payments of other long-term debt obligations-------- (7,000) (54,000) (42,000) Principal payments of production payment obligation---------------- (24,854) (20,621) (14,611) Proceeds from exercise of stock options--------------------------- 2,026 703 123 Proceeds from issuance of common stock----------------------------- -- 43,313 -- Debt issue expenses paid----------- -- (1,100) -- Increase in production payment----- -- -- 13,193 Purchase of 8% debentures, due 2005------------------------------ -- -- (7,621) Net cash used in financing activities----------------- (21,828) (32,705) (33,916) Net increase (decrease) in cash and cash investments-------------------- 1,676 (205) 233 Cash and cash investments at the beginning of the year--------------- 5,037 5,242 5,009 Cash and cash investments at the end of the year------------------------- $ 6,713 $ 5,037 $ 5,242 Reconciliation of net income to net cash provided by operating activities: Net income------------------------- $ 25,061 $ 18,495 $ 11,658 Adjustments to reconcile net income to net cash provided by operating activities -- Gains on purchase of 8% debentures, due 2005: Ordinary----------------------- -- -- (646) Extraordinary, net of taxes---- -- -- (1,336) Gains on sales------------------- (679) (1,702) (44) Depreciation, depletion and amortization-------------------- 40,693 42,302 37,521 Dry hole and impairment---------- 4,690 9,314 4,554 Interest capitalized------------- (451) (391) (637) Change in assets and liabilities: Decrease in United Kingdom tax escrow deposit---------------- -- -- 2,083 (Increase) decrease in accounts receivable-------------------- 4,172 (1,191) 4,799 (Increase) decrease in federal income taxes and interest receivable-------------------- (3,320) -- 29,002 Increase in other current assets------------------------ (360) (27) (32) (Increase) decrease in other assets------------------------ 838 (3,515) 1,641 Increase (decrease) in accounts payable----------------------- (1,592) 733 (1,322) Increase (decrease) in accrued interest payable-------------- 80 (2,480) (1,342) Increase (decrease) in accrued payroll and related benefits---------------------- 63 (244) 375 Increase (decrease) in other current liabilities----------- (20) (9) 62 Increase in deferred federal income taxes------------------ 13,356 8,669 1,268 Increase (decrease) in deferred credits----------------------- 613 (2,243) 756 Net cash provided by operating activities-------------------------- $ 83,144 $ 67,711 $ 88,360
The accompanying notes to consolidated financial statements are an integral part hereof.
The accompanying notes to consolidated financial statements are an integral part hereof.
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION --
The consolidated financial statements include the accounts of Pogo Producing Company and its wholly-owned subsidiaries (the 'Company'), after elimination of all significant intercompany transactions.
INVENTORIES --
Inventories consist primarily of tubular goods used in the Company's operations and are stated at the lower of average cost or market value.
INTEREST CAPITALIZED --
Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated.
EARNINGS PER SHARE --
Earnings per common and common equivalent share are based on weighted average shares of Common Stock outstanding assuming exercise of dilutive stock options. The 8% convertible subordinated debentures, due 2005 are common stock equivalents and were anti-dilutive in all periods presented. The 10.25% convertible subordinated notes, due 1999 are not common stock equivalents and were anti-dilutive in all periods presented. The weighted average number of common and common stock equivalent shares outstanding for primary earnings per share was 32,860,000, 27,929,000, and 27,611,000 in 1993, 1992, and 1991, respectively. The additional shares which would be assumed to be outstanding in the fully diluted calculation are not sufficient to change the earnings per share amounts reported in the primary calculation.
PRODUCTION IMBALANCES --
Owners of an oil and gas property often take more or less production from a property than entitled to based on their ownership percentages in the property. This results in a condition known in the industry as a production imbalance. The Company follows the 'take' (cash) method of accounting for production imbalances. Under this method, the Company recognizes revenues on production as it is taken and delivered to its purchasers. The Company's crude oil imbalances are not significant. At December 31, 1993, the Company had taken approximately 10,195 MMcf of natural gas less than it was entitled to based on its interest in those properties, and approximately 7,295 MMcf more than its entitlement on other properties placing the Company at year end in a net under-delivered position of approximately 2,900 MMcf of natural gas based on its working interest ownership in the properties.
OIL AND GAS ACTIVITIES AND DEPRECIATION, DEPLETION, AND AMORTIZATION --
The Company follows the successful efforts method of accounting for its oil and gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. The provision for depreciation, depletion and amortization is determined on a field-by-field basis using the units of production method.
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Other properties are depreciated on a straight-line method in amounts which in the opinion of management are adequate to allocate the cost of the properties over their estimated useful lives.
CONSOLIDATED STATEMENTS OF CASH FLOWS --
For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and as such will not be disclosed in the Consolidated Statement of Cash Flows. Certain such noncash transactions are disclosed in the Consolidated Statements of Shareholders' Equity relating to the acquisition of treasury stock in exchange for stock options exercised and the conversion of a debenture into Common Stock. In addition, the Company exchanged its working interest in thirteen Gulf of Mexico oil and gas properties for an increased working interest in five other Gulf of Mexico oil and gas properties in a noncash 'like kind' exchange. The oil and gas property and accumulated depreciation, depletion and amortization accounts as reflected in the Consolidated Balance Sheets have been adjusted to reflect the appropriate amounts to record the working interests acquired and disposed of. The oil and gas reserves acquired and disposed of are reflected as purchases and sales in the roll forward 'Estimates of Proved Reserves' included in the 'Unaudited Supplementary Financial Data' included elsewhere herein.
COMMITMENTS AND CONTINGENCIES --
The Company's rent expense was $868,000, $808,000, and $1,069,000 in 1993, 1992, and 1991, respectively. The Company has lease commitments for office space of $809,000 per year in each year for 1994 through 1997 and $777,000 in 1998.
(2) INCOME TAXES
The components of federal income tax expense (benefit) for each of the three years in the period ended December 31, 1993, are as follows (expressed in thousands):
1993 1992 1991 United States Current-------------------------- $ 2,800 $ 1,500 $ 2,900 Deferred (a)--------------------- 12,360 8,672 1,125 Foreign Current-------------------------- (179) 20 269 Total------------------------ $ 14,981 $ 10,192 $ 4,294
(a) Excludes $688,000 of deferred taxes on a $2,024,000 extraordinary item in 1991.
Total federal income tax expense (benefit) for each of the three years in the period ended December 31, 1993, differs from the amounts computed by applying the statutory federal income tax rate to income before taxes as follows (expressed as a percent of pretax income):
1993 1992 1991 Federal statutory income tax rate---- 35.0% 34.0% 34.0% Increases (reductions) resulting from: Statutory depletion in excess of tax basis---------------------- (0.4) (0.1) (0.9) Foreign taxes-------------------- 2.9 1.4 1.8 Life insurance loan proceeds----- -- -- (5.9) Other---------------------------- -- 0.2 0.4 37.5% 35.5% 29.4%
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The deferred federal income tax provision is the result of the difference between deferred tax liabilities determined at each balance sheet date. The deferred tax liabilities are determined by applying current tax laws to temporary differences in the recognition of revenue and expense for tax and financial purposes. Temporary differences arise primarily from the amortization of productive intangible drilling costs which are capitalized and amortized for financial statement purposes but are deducted for income tax purposes and differences in depreciation rates for tangible assets for financial and tax reporting purposes.
As of December 31, 1993, the Company has general business credits of approximately $1,400,000, which can be used to reduce future income taxes. In addition, the Company has alternative minimum tax credits of approximately $4,235,000 which can be used to reduce future regular income taxes payable.
(3) LONG-TERM DEBT
Long-term debt and the amount due within one year at December 31, 1993 and 1992, consists of the following (dollars expressed in thousands):
DECEMBER 31, 1993 1992 Senior debt -- Bank revolving credit agreements debt: Prime rate loans------------- $ 27,000 $ 9,000 LIBO Rate loans-------------- 40,000 50,000 Certificate of deposit rate loans---------------------- -- -- Total senior debt-------------------- 67,000 59,000 Subordinated debt -- 10.25% Convertible subordinated notes, due 1999, $4,000 annual sinking fund requirement-------------------- 24,000 28,000 8% Convertible subordinated debentures, due 2005, $1,540 sinking fund requirement in 1995 and a $3,000 annual sinking fund requirement thereafter--------- 43,539 46,260 Total subordinated debt-------------- 67,539 74,260 Total debt--------------------------- 134,539 133,260 Amount due within one year -- Current portion of long-term debt, consisting of sinking fund requirement on 10.25% notes---- (4,000) (4,000) Long-term debt----------------------- $ 130,539 $ 129,260
The bank revolving credit agreement entered into in December 1993, extends to the Company a $100,000,000 revolving/term credit facility which will be fully revolving until June 29, 1996 and will convert to a term loan with eight quarterly installments commencing July 31, 1996. The amount that may be borrowed under the facility may not exceed a borrowing base, determined semiannually by the lenders based on the discounted present value of the Company's oil and gas reserves and the provisions of the agreement. The borrowing base currently exceeds $100,000,000. The agreement provides that total debt and total debt for borrowed money, as defined, may not exceed $230,000,000 and $200,000,000, respectively. The facility is governed by various financial covenants including the maintenance of positive working capital (excluding current maturities of debt), a fixed charge ratio, as defined, of 1.7 or greater, a $10,000,000 limit on other senior debt, and a $10,000,000 limit on prepayment (without refinancing) of subordinated debt in any one year and $20,000,000 in total through July 31, 1996. Upon the occurrence of an event of default or certain other specified events, the banks would be entitled to a security interest in the borrowing base properties, which constitute substantially all of the Company's domestic oil and gas properties. Borrowings under the facility bear
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
interest at Base (Prime) rate plus 1/4%, a certificate of deposit rate plus 1 7/8%, or LIBOR plus 1 3/4%, at the Company's option. A commitment fee of 1/2 of 1% per annum of the unborrowed amount under the facility is also due. The Company incurred commitment fees of $149,000 in 1993, $80,000 in 1992, and $132,000 in 1991 under this and prior revolving credit agreements.
The 10.25% convertible notes are convertible into Common Stock at $23.95 per share subject to adjustment under certain circumstances, including stock splits. The convertible debentures are redeemable at the option of the Company at 103.7% through April 1, 1994, at 102.95% through April 1, 1995, and decreasing percentages thereafter, under certain market conditions, and are subject to mandatory annual sinking fund requirements of $4,000,000 which commenced April 1, 1990. The sinking fund requirements will be sufficient to retire 90% of the issue prior to maturity.
The 8% convertible debentures are convertible into Common Stock at $39.50 per share subject to adjustment under certain circumstances, including stock splits. These convertible debentures are redeemable at the option of the Company at 102.8% through December 30, 1994, and decreasing percentages thereafter, and are subject to mandatory annual sinking fund requirements of $3,000,000 which commenced December 31, 1990. Such requirements will be sufficient to retire 75% of the issue prior to maturity. To date, the Company has purchased $13,740,000 principal amount of the bonds at less than face value resulting in ordinary gains of $646,000 and $902,000 in 1991 and 1990, respectively, on the bonds purchased in satisfaction of sinking fund requirements in those years, and a $1,336,000 extraordinary gain (net of taxes) in 1991 on the bonds purchased in excess of current sinking fund requirements. The Company currently has $4,460,000 face amount of the bonds purchased in excess of current sinking fund requirements which may be tendered in satisfaction of future sinking fund requirements. The Company elected to make the December 31, 1993 sinking fund payment in cash.
Current maturities and sinking fund requirements during the next five years in connection with the above long-term debt are $4,000,000 in 1994, $5,540,000 in 1995, $27,100,000 in 1996, $40,500,000 in 1997 and $20,400,000 in 1998. Included in the current maturities reflected above are $20,100,000 in 1996, $33,500,000 in 1997, and $13,400,000 in 1998 relative to bank debt. The Company has established a history of refinancing its bank debt before scheduled maturities and expects to do so again before the amortization of bank debt commences in 1996.
In 1993, the Company entered into interest rate swap agreements on $15,000,000 of its bank debt, $5,000,000 of which terminated in January, 1994 and $10,000,000 of which terminates in July, 1994. The swap agreements effectively change the interest rates from variable to fixed rates which average 5.78% on the $15,000,000.
(4) SALES TO MAJOR CUSTOMERS
The Company is an oil and gas exploration and production company that until recently sold its production to relatively few customers. As a result of recent changes in the natural gas industry, the Company, like many other producers, now sells its natural gas to numerous customers on a month-to-month basis. The Company no longer has a significant amount of its natural gas reserves committed to long-term (multiple year) contracts at higher than prevailing market prices. Sales to the following customers exceeded 10 percent of oil and gas revenues during the years indicated (expressed in thousands):
1993 1992 1991 Scurlock Oil Company----------------- $ 38,510 $ 39,729 $ 38,554 United Gas Pipeline Company---------- $ -- $ -- $ 21,074 Enron Corp--------------------------- $ 16,437 $ -- $ --
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(5) EMPLOYEE BENEFITS
A total of 2,353,069 shares of Common Stock are reserved for issuance to key employees and non-employee directors under the Company's stock option plans. The stock option plans authorize the granting of options at prices equivalent to the market value at the date of grant. Options generally become exercisable in three annual installments commencing one year after the date granted and, if not exercised, expire 10 years from the date of grant. At January 1, 1993, 1,544,484 shares were issuable under stock options outstanding. Options for 291,500 shares were granted during 1993 at prices ranging from $15.13 to $19.00 per share. During 1993, 345,308 options were exercised at prices ranging from $4.38 to $16.25 per share and no options were cancelled. At December 31, 1993, options to purchase 1,490,676 shares were outstanding (1,098,815 were exercisable) at prices ranging from $4.38 to $19.00.
The Company has a tax-advantaged savings plan in which all salaried employees may participate. Under such plan, a participating employee may allocate up to 10% of his salary, and the Company makes matching contributions of up to 6% thereof. Funds contributed by the employee and the matching funds contributed by the Company are held in trust by a bank trustee in six separate funds. Funds contributed by the employee and earnings and accretions thereon may be used to purchase shares of Common Stock, invest in a money market fund or invest in four stock, bond, or blended stock and bond mutual funds according to instructions from the employee. Matching funds contributed to the savings plan by the Company are invested only in Common Stock. The Company contributed $125,000 to the savings plan in 1993, $288,000 in 1992, and $265,000 in 1991.
A trusteed retirement plan has been adopted by the Company for its salaried employees. The benefits are based on years of service and the employee's average compensation for five consecutive years within the final ten years of service which produce the highest average compensation. The Company makes annual contributions to the plan in the amount of retirement plan cost accrued or the maximum amount which can be deducted for federal income tax purposes. The following table sets forth the plan's funded status (in thousands of dollars) as of December 31, 1993, 1992, and 1991.
1993 1992 1991 Actuarial present value (discounted at 7 1/2, 8 1/4, and 8 1/2%, respectively) of benefit obligations: Accumulated benefit obligations -- Vested----------------------- $ 4,019 $ 3,120 $ 2,997 Nonvested-------------------- 717 701 657 Total accumulated benefit obligations------------------ 4,736 3,821 3,654 Projected salary increases (escalated at 6%) and other changes------------------------ 1,500 2,653 2,441 Projected benefit obligations for service rendered to date------- 6,236 6,474 6,095 Plan assets at fair value, primarily listed securities with an expected long-term rate of return of 8 1/4%----------------------------- 13,481 13,830 13,505 Plan assets in excess of projected benefit obligations---------------- 7,245 7,356 7,410 Unrecognized: Net overfunding being recognized over 15 years------------------ (750) (853) (957) Net gain arising from the difference between actual experience and that assumed---- (3,209) (3,956) (4,438) Prior service cost--------------- (473) (41) (45) Accrued retirement plan asset-------- $ 2,813 $ 2,506 $ 1,970
(TABLE CONTINUED ON FOLLOWING PAGE)
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1993 1992 1991 Retirement plan cost (benefit) for 1993, 1992, and 1991 included the following components: Service cost, benefits accruing each year with proration for future salary increases-------- $ 611 $ 514 $ 501 Interest cost on projected benefit obligations------------ 524 451 508 Actual return on plan assets----- (1,164) (1,141) (3,882) Net amortization and deferral---- (278) (360) 2,853 Accrued retirement plan cost (benefit)---------------------- $ (307) $ (536) $ (20)
Effective January 1, 1992, the Company adopted the provisions of the Statement of Financial Accounting Standards No. 106, 'Employers' Accounting for Postretirement Benefits Other Than Pensions.' The Company currently provides full medical benefits to its retired employees and dependents. For current employees, the Company assumes all or a portion of postretirement medical and term life insurance costs based on the employee's age and length of service with the Company. The postretirement medical plan has no assets and is currently funded by the Company on a pay-as-you-go basis.
The following is an analysis (in thousands of dollars) of the annual expense and activity in the deferred cost and benefits obligation accounts for 1992 and 1993. The computation assumes that future increases in medical costs will trend down from 13% to 7% per year over the next 12 years for purposes of estimating future costs. The medical cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed medical cost trend rate by one percent in each year would increase the aggregate of service and interest cost components of net periodic postretirement benefits cost for 1993 by $164,000 and the accumulated postretirement benefits obligation as of December 31, 1993 by $1,171,000.
ANNUAL DEFERRED BENEFITS EXPENSE COSTS OBLIGATION Transition obligation at January 1, 1992------------------------------- $ 4,263 $ (4,263) Amortization of transition cost over 14 years representing the average remaining service period of eligible employees----------------- $ 305 (305) 305 Service cost, including interest----- 303 Interest cost on transition obligation------------------------- 362 1992 expense------------------------- $ 970 (970) Current benefits paid---------------- 170 Balance at December 31, 1992--------- 3,958 (4,758) Amortization of transition costs over 14 years--------------------------- $ 305 (305) 305 Service cost, including interest----- 368 Interest cost on transition obligation------------------------- 407 1993 expense------------------------- $ 1,080 (1,080) Current benefits paid---------------- 246 Unrecognized loss-------------------- (1,400) Balance at December 31, 1993--------- $ 3,653 Plan assets at fair value------------ -- Funded status at December 31, 1993 (discounted at 7 1/2%)---- $ (6,687)
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The accumulated postretirement benefit obligation (in thousands of dollars) at December 31, 1993 is attributable to the following groups:
Retirees and beneficiaries----------------------------------- $ 2,739 Dependents of retirees--------------------------------------- 1,188 Fully eligible active employees------------------------------ 577 Active employees, not fully eligible------------------------- 2,183 $ 6,687
(6) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value.
CASH AND CASH INVESTMENTS
The carrying value approximates fair value because of the short maturity of these investments.
DEBT
INSTRUMENT BASIS OF FAIR VALUE ESTIMATE Bank revolving credit agreement debt------------------------------- Fair value is carrying value based on recent 1993 renegotiation with banks 10.25% Convertible subordinated notes, due 1999-------------------- Fair value is 103.7% of carrying value based on the redemption premium at December 31, 1993 8% Convertible subordinated debentures, due 2005--------------- Fair value is 99.5% of carrying value based on the quoted market price for this publicly traded debt at December 31, 1993
The estimated fair value of the Company's financial instruments (in thousands of dollars) are as follows:
CARRYING FAIR VALUE VALUE Cash and cash investments------------ $ 6,713 $ 6,713 Debt--------------------------------- (134,539) (135,209)
UNAUDITED SUPPLEMENTARY FINANCIAL DATA
OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities excludes non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. United States income tax expense was determined by applying the statutory rates to pretax operating results with adjustments for permanent differences. Kingdom of Thailand tax expense was determined by applying the statutory tax rate to Thailand taxable income.
UNITED KINGDOM OF TOTAL STATES THAILAND (EXPRESSED IN THOUSANDS) -------------------------------------- Oil and gas revenues----------------- $ 136,553 $ 136,525 $ 28 Lease operating expense-------------- (26,633) (26,633) -- Exploration expense------------------ (2,455) (1,060) (1,395) Dry hole and impairment expense------ (4,690) (2,737) (1,953) Depreciation, depletion and amortization expense--------------- (40,224) (40,193) (31) Pretax operating results------------- 62,551 65,902 (3,351) Income tax (expense) benefit--------- (22,712) (22,891) 179 Operating results-------------------- $ 39,839 $ 43,011 $ (3,172)
-------------------------------------- Oil and gas revenues----------------- $ 139,128 $ 139,128 $ -- Lease operating expense-------------- (25,842) (25,842) -- Exploration expense------------------ (3,102) (1,876) (1,226) Dry hole and impairment expense------ (9,314) (9,314) -- Depreciation, depletion and amortization expense--------------- (41,849) (41,834) (15) Pretax operating results------------- 59,021 60,262 (1,241) Income tax expense------------------- (20,510) (20,490) (20) Operating results-------------------- $ 38,511 $ 39,772 $ (1,261)
-------------------------------------- Oil and gas revenues----------------- $ 124,425 $ 124,425 $ -- Lease operating expense-------------- (28,192) (28,192) -- Exploration expense------------------ (2,408) (2,261) (147) Dry hole and impairment expense------ (4,554) (4,554) -- Depreciation, depletion and amortization expense--------------- (36,970) (36,965) (5) Pretax operating results------------- 52,301 52,453 (152) Income tax expense------------------- (17,725) (17,698) (27) Operating results-------------------- $ 34,576 $ 34,755 $ (179)
The following table sets forth Pogo's capitalized costs (expressed in thousands) incurred for oil and gas producing activities during the years indicated.
1993 1992 1991 Capitalized costs incurred: Property acquisition (United States)------------------------ $ 1,520 $ 11,578 $ 7,697 Exploration -- United States---------------- 8,267 3,865 3,546 Kingdom of Thailand---------- 4,583 1,412 -- Development -- United States---------------- 57,648 20,717 37,025 Kingdom of Thailand---------- -- -- -- Interest capitalized (United States)------------------------ 451 391 637 $ 72,469 $ 37,963 $ 48,905 Provision for depreciation, depletion, and amortization: United States---------------- $ 40,193 $ 41,834 $ 36,965 Kingdom of Thailand---------- 31 15 5 $ 40,224 $ 41,849 $ 36,970
UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)
The following information regarding estimates of the Company's proved oil and gas reserves, which are located offshore in United States waters of the Gulf of Mexico, onshore in the United States and offshore in the Kingdom of Thailand is based on reports prepared by Ryder Scott Company Petroleum Engineers. Their summary report dated January 28, 1994 is set forth as an exhibit to this Annual Report and includes definitions and assumptions that served as the basis for the discussion under the caption 'Item 1, Business -- Exploration and Production Data; Reserves'. Such definitions and assumptions should be referred to in connection with the following information.
ESTIMATES OF PROVED RESERVES
OIL, CONDENSATE AND NATURAL GAS LIQUIDS NATURAL GAS (BBLS.) (MMCF) Proved reserves (located in the United States) as of December 31, 1990------------------ 19,090,376 217,500 Revisions of previous estimates---------------------- 782,707 3,531 Extensions, discoveries, and other additions---------------- 1,612,983 16,157 Purchase of properties----------- 263,495 4,913 Sales of properties-------------- (5) (4) Estimated 1991 production-------- (2,931,465) (39,362) Proved reserves (located in the United States) as of December 31, 1991------------------ 18,818,091 202,735 Revisions of previous estimates---------------------- 1,721,385 20,284 Extensions, discoveries, and other additions (including 2,576,907 barrels and 10,668 MMcf located in the Kingdom of Thailand)---------------------- 5,486,273 19,126 Purchase of properties----------- 335,750 10,237 Sales of properties-------------- (194,606) (4,733) Estimated 1992 production-------- (3,611,105) (40,581) Proved reserves (located in the United States except for 2,576,907 barrels and 10,668 MMcf located in the Kingdom of Thailand) as of December 31, 1992------------------ 22,555,788 207,068 Revisions of previous estimates---------------------- 342,022 1,148 Extensions, discoveries, and other additions (including 2,847,906 barrels and 22,806 MMcf located in the Kingdom of Thailand)----------- 9,764,408 55,626 Purchase of properties----------- 182,610 13,192 Sales of properties-------------- (356,514) (11,849) Estimated 1993 production-------- (4,219,873) (32,319) Proved reserves (located in the United States except for 5,424,813 barrels and 33,474 MMcf located in the Kingdom of Thailand) as of December 31, 1993------------------ 28,268,441 232,866 Proved developed reserves (located in the United States) as of: December 31, 1990---------------- 17,841,751 202,471 December 31, 1991---------------- 17,549,830 188,090 December 31, 1992---------------- 18,798,149 175,523 December 31, 1993---------------- 20,976,194 183,139
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES
TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND (EXPRESSED IN THOUSANDS) Future gross revenues---------------- $ 869,783 $ 744,201 $ 125,582 Future production costs: Lease operating expense---------- (186,464) (158,934) (27,530) Future development and abandonment costs------------------------------ (133,258) (79,735) (53,523) Future net cash flows before income taxes------------------------------ 550,061 505,532 44,529 Discount at 10% per annum------------ (146,221) (118,858) (27,363) Discounted future net cash flow Before income taxes---------------- 403,840 386,674 17,166 Future income taxes, net of discount at 10% per annum------------------- (103,580) (98,788) (4,792) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves-------- $ 300,260 $ 287,886 $ 12,374
Future gross revenues---------------- $ 856,238 $ 791,865 $ 64,373 Future production costs: Lease operating expense---------- (179,721) (173,355) (6,366) Future development and abandonment costs------------------------------ (105,843) (80,887) (24,956) Future net cash flows before income taxes------------------------------ 570,674 537,623 33,051 Discount at 10% per annum------------ (165,573) (146,730) (18,843) Discounted future net cash flow before income taxes---------------- 405,101 390,893 14,208 Future income taxes, net of discount at 10% per annum------------------- (97,444) (91,848) (5,596) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves-------- $ 307,657 $ 299,045 $ 8,612
Future gross revenues---------------- $ 725,360 $ 725,360 $ -- Future production costs: Lease operating expense---------- (163,262) (163,262) -- Future development and abandonment costs------------------------------ (67,671) (67,671) -- Future net cash flows before income taxes------------------------------ 494,427 494,427 -- Discount at 10% per annum------------ (144,673) (144,673) -- Discounted future net cash flow before income taxes---------------- 349,754 349,754 -- Future income taxes, net of discount at 10% per annum------------------- (76,423) (76,423) -- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves-------- $ 273,331 $ 273,331 $ --
The standardized measure of discounted future net cash flows from the production of proved reserves is developed as follows:
1. Estimates are made of quantities of proved reserves and the future periods in which they are expected to be produced based on year end economic conditions.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- (CONTINUED)
2. The estimated future gross revenues from proved reserves are priced on the basis of year end prices, except in those instances where fixed and determinable natural gas price escalations are covered by contracts.
3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs based on year end cost estimates, and the estimated effect of future income taxes.
The standardized measure of discounted future net cash flows does not purport to present the fair market value of Pogo's oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The following are the principal sources of change in the standardized measure of discounted future net cash flows. All amounts are related to changes in reserves located in the United States unless otherwise noted.
YEAR ENDED DECEMBER 31, 1993 TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND (EXPRESSED IN THOUSANDS) Beginning balance-------------------- $ 307,657 $ 299,045 $ 8,612 Revisions to prior years' proved reserves: Net changes in prices and production costs--------------- (41,775) (34,842) (6,933) Net changes due to revisions in quantity estimates------------- 4,066 4,066 -- Net changes in estimates of future development costs------- 662 (871) 1,533 Accretion of discount------------ 40,510 39,089 1,421 Changes in production rate------- 5,134 6,728 (1,594) Other---------------------------- 2,278 3,935 (1,657) Total revisions-------------- 10,875 18,105 (7,230) New field discoveries and extensions, net of future production and development costs:----------------- 39,247 29,059 10,188 Purchases of properties-------------- 22,516 22,516 -- Sales of properties------------------ (19,633) (19,633) -- Sales of oil and gas produced, net of production costs------------------- (110,870) (110,870) -- Previously estimated development costs incurred--------------------- 56,604 56,604 -- Net change in income taxes----------- (6,136) (6,940) 804 Net change in standardized measure of discounted future net cash flows------------- (7,397) (11,159) 3,762 Ending balance----------------------- $ 300,260 $ 287,886 $ 12,374
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- (CONTINUED)
YEAR ENDED DECEMBER 31, 1992 1991 (EXPRESSED IN THOUSANDS) Beginning balance-------------------- $ 273,331 $ 400,937 Revisions to prior years' proved reserves: Net changes in prices and production costs--------------- 38,348 (174,464) Net changes due to revisions in quantity estimates------------- 42,829 9,940 Net changes in estimates of future development costs------- (21,015) (28,740) Accretion of discount------------ 34,975 52,517 Changes in production rate------- (5,733) (6,518) Other---------------------------- 6,607 (7,404) Total revisions-------------- 96,011 (154,669) New field discoveries and extensions, net of future production and development costs: United States---------------- 29,552 28,286 Kingdom of Thailand---------- 14,208 -- Purchases of properties-------------- 13,870 6,827 Sales of properties------------------ (7,430) (7) Sales of oil and gas produced, net of production costs------------------- (111,581) (92,895) Previously estimated development costs incurred--------------------- 20,717 37,039 Net change in income taxes: United States---------------- (15,425) 47,813 Kingdom of Thailand---------- (5,596) -- Net change in standardized measure of discounted future net cash flows------------- 34,326 (127,606) Ending balance----------------------- $ 307,657 $ 273,331
QUARTERLY RESULTS
Summaries of Pogo's results of operations by quarter for the years 1993 and 1992 are as follows:
QUARTER ENDED MAR. 31 JUNE 30 SEPT. 30 DEC. 31 (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues----------------------------- $34,681 $ 34,533 $ 37,210 $ 33,130 Gross profit(a)---------------------- $17,331 $ 15,391 $ 17,903 $ 14,458 Net income--------------------------- $ 7,160 $ 5,596 $ 7,161 $ 5,144 Earnings per share (primary and fully diluted)-------- $ 0.22 $ 0.17 $ 0.22 $ 0.16 Revenues----------------------------- $28,347 $ 34,072 $ 34,907 $ 43,504 Gross profit(a)---------------------- $ 7,147 $ 12,646 $ 16,165 $ 24,312 Net income (loss)-------------------- $(1,216) $ 3,276 $ 5,535 $ 10,900 Earnings (loss) per share (primary and fully diluted)-------- $ (0.04) $ 0.12 $ 0.20 $ 0.38
(a) Represents revenues less lease operating, exploration, dry hole and impairment, and depreciation, depletion and amortization expenses.
ITEM 9.

ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not applicable.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information regarding nominees and continuing directors in the Company's definitive Proxy Statement for its annual meeting to be held on April 26, 1994, to be filed within 120 days of December 31, 1993 pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the Company's '1994 Proxy Statement'), is incorporated herein by reference. See also Item S-K 401(b) appearing in Part I of this Form 10-K.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION.
The information regarding executive compensation in the Company's 1994 Proxy Statement, other than the information regarding the Compensation Committee Report on Executive Compensation, is incorporated herein by reference.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information regarding ownership of the Company securities by management and certain other beneficial owners in the Company's 1994 Proxy Statement is incorporated herein by reference.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information regarding certain relationships and related transactions with management in the Company's 1994 Proxy Statement is incorporated herein by reference.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, FINANCIAL STATEMENT SCHEDULES AND EXHIBITS PAGE 1. Financial Statements and Supplementary Data: Report of Independent Public Accountants----------------- 30 Consolidated statements of income------------------------ 31 Consolidated balance sheets------------------------------ 32 Consolidated statements of cash flows-------------------- 33 Consolidated statements of shareholders' equity---------- 34 Notes to consolidated financial statements--------------- 35 2. Financial Statement Schedules: V --Property and Equipment for the Years Ended December 31, 1993, 1992 and 1991------------------- S-1 VI --Reserves for Depreciation, Depletion and Amortization of Property and Equipment For the Years Ended December 31, 1993, 1992 and 1991------- S-1 X --Supplementary Income Statement Information For the Years Ended December 31, 1993, 1992 and 1991--- S-2 Schedules other than those listed above are omitted because they are not required, are not applicable or the information required has been included elsewhere herein.
3. Exhibits:
*3(a ) -- Restated Certificate of Incorporation of Pogo Producing Company. (Exhibit 3(a), Annual Report on Form 10-K for the year ended December 31, 1987, File No. 0-5468).
*3(a)(1) -- Certificate of Designation, Preferences and Rights of Preferred Stock of Pogo Producing Company, dated March 25, 1987. (Exhibit 3(a)(1), Annual Report on Form 10-K for the year ended December 31, 1987, File No. 0-5468).
*3(b) -- Bylaws of Pogo Producing Company, as amended and restated through July 24, 1990. (Exhibit 3(a), Quarterly Report on Form 10-Q for the quarter ended June 30, 1990, File No. 0-5468).
*4(a)(i) -- Credit Agreement dated as of September 23, 1992, among Pogo Producing Company, the lenders party thereto, Bank of Montreal as Agent, and Banque Paribas as Co-Agent. (Exhibit 10(a), Quarterly Report on Form 10-Q for the quarter ended September 30, 1992, File No. 1-7792).
4(a)(ii) -- First Amendment dated as of September 30, 1992 to Credit Agreement dated as of September 23, 1992, among Pogo Producing Company, the lenders party thereto, Bank of Montreal as Agent, and Banque Paribas as Co-Agent.
4(a)(iii) -- Second Amendment dated as of December 31, 1993 to Credit Agreement dated as of September 23, 1992, among Pogo Producing Company, the lenders party thereto, Bank of Montreal as Agent, and Banque Paribas as Co-Agent.
*4(b) -- Indenture dated as of October 15, 1980 to Chemical Bank, as Trustee. (Exhibit 4, File No. 2-69428). The Company agrees to furnish to the Commission upon request a copy of any agreement defining the rights of holders of long-term debt of the Company and all its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed under which the total amount of securities authorized does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising Exhibits 10(a) through 10(f)(14)(ii), inclusive)
*10(a) -- 1977 Stock Option Plan of Pogo Producing Company, as amended as of September 28, 1981 and July 24, 1984. (Exhibit 10(a), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468).
*10(a)(1) -- Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (with stock appreciation rights and without employment restrictions). (Exhibit 10(a)(1), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(2) -- Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (with stock option appreciation rights and without employment restrictions). (Exhibit 10(a)(2), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(3) -- Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (without stock appreciation rights and with employment restrictions). (Exhibit 10(a)(3), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(4) -- Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (without stock option appreciation rights and with employment restrictions). (Exhibit 10(a)(4), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(5) -- Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (with stock appreciation rights and with employment restrictions). (Exhibit 10(a)(5), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(6) -- Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (with stock option appreciation rights and with employment restrictions). (Exhibit 10(a)(6), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(7) -- Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (without stock appreciation rights and without employment restrictions). (Exhibit 10(a)(7), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(8) -- Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (without stock option appreciation rights and without employment restrictions). (Exhibit 10(a)(8), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(b) -- 1981 Stock Option Plan of Pogo Producing Company, as amended as of July 24, 1984. (Exhibit 10(b), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468).
*10(b)(1) -- Form of Stock Option Agreement under 1981 Nonqualified Stock Option Plan (with stock appreciation rights). (Exhibit 10(b)(1), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(b)(2) -- Form of Stock Option Agreement under 1981 Nonqualified Stock Option Plan (without stock appreciation rights). (Exhibit 10(b)(2), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(c) -- 1981 Incentive and Nonqualified Stock Option Plan of Pogo Producing Com- pany, as amended as of July 24, 1984. (Exhibit 10(c), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468).
*10(c)(1) -- Form of Stock Option Agreement under 1981 Incentive Stock Option Plan. (Exhibit 10(c)(1), Annual Report of Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(d) -- 1989 Incentive and Nonqualified Stock Option Plan of Pogo Producing Com- pany, as amended and restated effective January 22, 1991. (Exhibit 10(d), Annual Report on Form 10-K for the year ended December 31, 1991, file No. 0-5468).
*10(d)(1) -- Form of Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option Plan, as amended and restated effective January 22, 1991. (Exhibit 10(d)(1), Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-5468).
*10(d)(2) -- Form of Director Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option Plan, as amended and restated effective January 22, 1991. (Exhibit 10(d)(2), Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-5468).
*10(e) -- Form of Letter Agreement respecting treatment of options upon change in control. (Exhibit 19(f), Quarterly Report on Form 10-Q for the quarter ended June 30, 1982. File No. 0-5468).
*10(f)(1) -- Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated February 1, 1992. (Exhibit 19(a)(1), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792).
*10(f)(2)(i) -- Extension Agreement to Continue Employment Agreement between Stuart P. Burbach and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(2), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792).
10(f)(2)(ii) -- Extension Agreement to Continue Employment Agreement between Stuart P. Burbach and Pogo Producing Company, dated as of February 1, 1994.
*10(f)(3) -- Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated February 1, 1992. (Exhibit 19(a)(2), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792).
*10(f)(4)(i) -- Extension Agreement to Continue Employment Agreement between Jerry A. Cooper and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(4), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792).
10(f)(4)(ii) -- Extension Agreement to Continue Employment Agreement between Jerry A. Cooper and Pogo Producing Company, dated as of February 1, 1994.
*10(f)(5) -- Employment Agreement by and between Pogo Producing Company and Kenneth R. Good, dated February 1, 1992. (Exhibit 19(a)(3), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792).
*10(f)(6)(i) -- Extension Agreement to Continue Employment Agreement between Kenneth R. Good and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(6), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792).
10(f)(6)(ii) -- Extension Agreement to Continue Employment Agreement between Kenneth R. Good and Pogo Producing Company, dated as of February 1, 1994.
*10(f)(7) -- Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated February 1, 1992. (Exhibit 19(a)(4), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792).
*10(f)(8)(i) -- Extension Agreement to Continue Employment Agreement between R. Phillip Laney and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(8), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792).
10(f)(8)(ii) -- Extension Agreement to Continue Employment Agreement between R. Phillip Laney and Pogo Producing Company, dated as of February 1, 1994.
*10(f)(9) -- Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated February 1, 1992. (Exhibit 19(a)(5), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792).
*10(f)(10)(i) -- Extension Agreement to Continue Employment Agreement between John O. McCoy, Jr. and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(10), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792).
10(f)(10)(ii) -- Extension Agreement to Continue Employment Agreement between John O. McCoy, Jr. and Pogo Producing Company, dated as of February 1, 1994.
*10(f)(11) -- Employment Agreement by and between Pogo Producing Company and D. Stephen Slack, dated February 1, 1992. (Exhibit 19(a)(6), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792).
*10(f)(12)(i) -- Extension Agreement to Continue Employment Agreement between D. Stephen Slack and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(12), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792).
10(f)(12)(ii) -- Extension Agreement to Continue Employment Agreement between D. Stephen Slack and Pogo Producing Company, dated as of February 1, 1994.
*10(f)(13) -- Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated February 1, 1992. (Exhibit 19(a)(7), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792).
*10(f)(14)(i) -- Extension Agreement to Continue Employment Agreement between Paul G. Van Wagenen and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(14), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792).
10(f)(14)(ii) -- Extension Agreement to Continue Employment Agreement between Paul G. Van Wagenen and Pogo Producing Company, dated as of February 1, 1994.
*10(g) -- Undertaking by Pogo Producing Company dated as of August 8, 1977. (Exhibit 10(e), Annual Report on Form 10-K for the year ended December 31, 1980, File No. 0-5468).
*10(h) -- Limited partnership agreement of Pogo Gulf Coast, Ltd. (Exhibit 19, Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 0-5468).
21 -- List of Subsidiaries of Pogo Producing Company.
23(a) -- Consent of Independent Public Accountants.
23(b) -- Consent of Independent Petroleum Engineers.
24 -- Powers of Attorney from each Director of Pogo Producing Company whose signature is affixed to this Form 10-K for the year ended December 31, 1993.
28 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers dated January 28, 1994 relating to oil and gas reserves of Pogo Producing Company.
* Asterisk indicates exhibits incorporated by reference as shown.
(B) REPORTS ON FORM 8-K
None
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
POGO PRODUCING COMPANY (REGISTRANT)
By: /s/ PAUL G. VAN WAGENEN PAUL G. VAN WAGENEN
CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF EXECUTIVE OFFICER
Date: February 28, 1994
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES INDICATED ON FEBRUARY 28, 1994.
SIGNATURES TITLE
/s/ PAUL G. VAN WAGENEN Principal Executive PAUL G. VAN WAGENEN Officer and Director CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF EXECUTIVE OFFICER
/s/ D. STEPHEN SLACK Principal Financial D. STEPHEN SLACK Officer and Director SENIOR VICE PRESIDENT, CHIEF FINANCIAL OFFICER AND TREASURER
/s/ THOMAS E. HART Principal Accounting THOMAS E. HART Officer VICE PRESIDENT AND CONTROLLER
TOBIN ARMSTRONG* Director TOBIN ARMSTRONG
JACK S. BLANTON* Director JACK S. BLANTON
W. M. BRUMLEY, JR.* Director W. M. BRUMLEY, JR.
JOHN B. CARTER, JR.* Director JOHN B. CARTER, JR.
WILLIAM L. FISHER* Director WILLIAM L. FISHER
WILLIAM E. GIPSON* Director WILLIAM E. GIPSON
GERRITT W. GONG* Director GERRITT W. GONG
J. STUART HUNT* Director J. STUART HUNT
FREDERICK A. KLINGENSTEIN* Director FREDERICK A. KLINGENSTEIN
NICHOLAS R. PETRY* Director NICHOLAS R. PETRY
JACK A. VICKERS* Director JACK A. VICKERS
*By: /s/ THOMAS E. HART THOMAS E. HART ATTORNEY-IN-FACT
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SCHEDULE X
POGO PRODUCING COMPANY AND SUBSIDIARIES SCHEDULE X -- SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991 (EXPRESSED IN THOUSANDS)
1993 1992 1991 Maintenance and repairs-------------- $ 3,658 $ 4,435 $ 6,498 Taxes, other than payroll and income taxes: Severance, ad valorem, franchise and other------------------------ $ 3,133 $ 2,423 $ 2,222
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