MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
SIGNIFICANT EVENTS IN 1994
-The Company had record levels of oil and gas production during 1994.
-The Company expended $189.7 million on exploration, development and
acquisition costs during 1994.
-The Company replaced production of its reserves in 1994 by 175 percent
on a barrel of oil equivalent - gas converted at 6:1 (BOE).
-The cost of finding of all reserves added in 1994 was $4.64 per BOE.
-The Company reduced its short-term and long-term debt by $172.6 million
during 1994.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Net cash provided by operating activities was $188.6 million for 1994, a
35 percent and 51 percent increase over the $139.4 million and $125.1 million
in 1993 and 1992, respectively. Cash and short-term cash investments
decreased to $22.2 million at December 31, 1994, from $176.4 million at
year-end 1993.
During 1994, the Company utilized its beginning cash balance and cash flow
from operations to reduce its debt by $172.6 million and to fund its
exploration, development and acquisition expenditures of $189.7 million. The
Company's current ratio (current assets divided by current liabilities) was
1.44:1 at December 31, 1994, compared with 1.75:1 at December 31, 1993.
RESERVES ADDED AND COST OF FINDING
During 1994, the Company spent $189.7 million on exploration, development
and acquisitions of oil and gas properties. Total proved gas reserves
increased from 691.5 billion cubic feet (BCF) at year-end 1993 to 778.9 BCF
at year-end 1994 and total proved oil reserves increased from 73.0 million
barrels at year-end 1993 to 75.5 million barrels at year-end 1994.
One accepted method of calculating cost of finding is to divide the
Company's expenditures for oil and gas exploration, development and
acquisitions by the BOE's added during the year. Using this method, the
Company's cost of finding for 1994 was $4.64 per BOE. A three year schedule
of cost of finding follows:
THREE
(BOE'S AND DOLLARS STATED IN MILLIONS, YEAR
EXCEPT FINDING COST) 1994 1993 1992 TOTAL
---------------------------------------------------------
Oil reserves added 11.5 33.3 10.8 55.6
Gas reserves added BOE (6:1) 29.4 66.9 8.4 104.7
---------------------------------------------------------
Total reserves added BOE 40.9 100.2 19.2 160.3
---------------------------------------------------------
---------------------------------------------------------
Cost incurred in oil and gas
acquisition, exploration
and development activities $190 $515 $76 $781
Average finding cost per BOE $4.64 $5.14 $3.96 $4.87*
<FN>
*Three year average
LONG-TERM FINANCING
Total long-term debt at December 31, 1994 was $376,956,000 compared with
$453,760,000 at December 31, 1993. Ratio of long-term debt to book capital
(defined as the Company's long-term debt plus its equity) at December 31,
1994 was 48 percent compared with 52 percent at December 31, 1993.
In October 1993, the Company issued $230,000,000 4 1/4% Convertible
Subordinated Notes Due 2003 which are convertible into common stock of the
Company, at any time prior to maturity, at $36.65 per share.
Also in October 1993, the Company issued $100,000,000 7 1/4% Notes Due
2023. The Company may not redeem any portion of these notes prior to maturity.
The Company borrowed $175 million on October 1, 1993 from its then
existing bank line of credit to bridge finance the acquisition of $305
million of producing properties. The proceeds from both October 1993 debt
issues were used to repay,
(This page contained two graphs in the body of the text: Gas Reserves Added
for three years and Oil Reserves Added for three years)
Page 15
in full, the bank debt on October 21, 1993, as well as for other general
corporate purposes.
The Company has a bank credit agreement with certain banks which provides
for maximum unsecured borrowings of $100 million at variable rates. The
Company borrowed $48 million on June 1, 1994, and used the proceeds, plus
available cash balances, to redeem its $125,000,000 10 1/8% Notes Due June 1,
1997. No other borrowings have occurred against the line of credit. The
interest rate is a variable rate based on the lower of one of three interest
rate options. The weighted average interest rate on the borrowings during
1994 was 5 percent.
During the next five years no principal payments of long-term debt are
required except for $48 million outstanding under the bank credit agreement,
which is due May 31, 1997.
In conjunction with the acquisition of certain producing properties from
Freeport-McMoRan, the Company issued a short-term installment note for $95.6
million on October 1, 1993. On January 4, 1994, the Company paid the
installment note including accrued interest.
On May 10, 1993, the Company called its $100,000,000 7 1/4% Convertible
Debentures Due 2012. As a result of the call for redemption, owners of
$98,155,000 of the debentures elected to convert into a total of 5,001,373
shares of common stock. The debentures were converted into shares of the
Company's common stock at $19 5/8 per share. The remaining $1,845,000 was
redeemed with cash at 103.63 percent of the principal amount, plus accrued
interest to the redemption date.
OTHER
The Company follows an entitlements method of accounting for its gas
imbalances. The Company's estimated gas imbalance receivables were $11.7
million and $12.9 million at December 31, 1994 and 1993, respectively, and
estimated gas imbalance liabilities were $10.5 million and $7.6 million at
December 31, 1994 and 1993, respectively. These imbalances are valued at the
amount which is expected to be received or paid to settle the imbalances. The
settlement of the imbalances can occur either during, or at the end of the
life of a well, on a volume basis or by cash settlement. The Company does not
expect that a significant portion of the settlements will occur in any one
year. Thus, the Company believes the periodic settlement of gas imbalances
will have little impact on its liquidity.
The Company has sold a number of nonstrategic onshore oil and gas
properties over the past three years, recognizing a gain of $137,000 and
$128,000 for 1994 and 1993, respectively, and a loss of $711,000 for 1992.
Total amounts of oil and gas reserves associated with these disposals during
the last three years were 1,008,000 barrels (BBLS) of oil and 5.0 BCF of gas.
The Company believes the disposal of nonstrategic properties furthers the
goal of concentrating its efforts on its strategic properties.
The Company has paid quarterly dividends of $.04 per share since August 21,
1989, and currently anticipates it will continue to pay quarterly dividends of
$.04 per share.
During 1993, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 109, "Accounting for Income Taxes." The effect of
adopting SFAS No. 109 was not material to the Company's financial position
and results of operations. For additional information on SFAS No. 109, see
Note 4 to the financial statements.
Also during 1993, the Company adopted SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." The effect of
adopting SFAS No. 106 was not material to the Company's financial position
and results of operations. For additional information on SFAS No. 106, see
Note 6 to the financial statements.
The Company adopted SFAS No. 112, "Employers' Accounting for
Postemployment Benefits" in 1994. The impact of SFAS No. 112 was not
material to the Company's consolidated financial position or results of
operations.
(This page contained two graphs in the body of the text: Costs Incurred for
Acquisitions, Exploration and Development for three years and Average Finding
Cost Per BOE for three years)
Page 16
RESULTS OF OPERATIONS
NET INCOME AND REVENUES
Net income for 1994 was $3.2 million, or $.06 per share, down 75 percent
from 1993 net income of $12.6 million, or $.26 per share, and down 92 percent
from 1992 net income of $41.2 million, or $.93 per share. Oil and gas
revenues for 1994 were $306.2 million, up 10 percent from 1993 and up 18
percent from 1992. Despite increased revenues and cash flows for 1994, which
resulted from higher production volumes for both oil and gas, net income for
the year decreased. This decrease was due to higher exploration and
depreciation, depletion and amortization (DD&A) expenses.
Average oil price in 1994 was $14.90 per barrel, a 6 percent decrease from
the 1993 average of $15.91 per barrel. Average gas price decreased 6 percent
in 1994 to $1.97 per thousand cubic feet (MCF) from the 1993 average of $2.10
per MCF. Exploration expense increased 49 percent in 1994, as compared to
1993, primarily due to increased dry hole expense in the Company's offshore
division, Canada and Tunisia. Such increases in exploration expense reflect
the Company's increased level of drilling activity in 1994. The current
year's DD&A increased 19 percent over 1993 due to higher production volumes
and slightly higher unit rates.
Revenues and net income for 1992 included a pretax gain of $27.9 million
on the sale of the Company's investment in Natural Gas Clearinghouse (NGC),
and the receipt of $7.5 million from a gas contract settlement.
NATURAL GAS INFORMATION
Gas sales for 1994 increased 10 percent to $174.5 million from $159.2
million in 1993. Gas sales in 1993 increased 19 percent from $134.2 million
in 1992. Average daily production in 1994 increased 17 percent to 247.6
million cubic feet (MMCF) from 211.1 MMCF in 1993. Average daily production
in 1993 increased 3 percent from 204.6 MMCF in 1992. Average daily production
during 1994 ranged from a low of 174.3 MMCF in October, as a result of the
Company's election to shut in approximately 80 MMCF per day due to low
prices, to a high of 276.1 MMCF in March.
The average gas price in 1994 decreased 6 percent to $1.97 per MCF, from
$2.10 per MCF in 1993. The average gas price in 1993 increased 8 percent from
$1.81 per MCF in 1992. In 1994, the Company's average gas prices ranged from
a low of $1.59 per MCF in October to a high of $2.34 per MCF in March. Gas
revenues for 1993 and 1992 reflect reduced values of $3.7 million and $3.4
million, respectively, relating to hedging production at prices below the
ultimate spot price for gas. This lowered the average gas price received by
$.048 per MCF and $.045 per MCF for 1993 and 1992, respectively. During 1994,
all gas hedging activity was accomplished by the Company's new wholly owned
subsidiary, Noble Gas Marketing, Inc. (NGM), which hedged approximately 11
percent of the Company's average daily production at prices ranging from
$1.33 to $1.92 per million British thermal units (MMBTU). The hedging gains
and losses for 1994 are included in gathering, marketing and processing
revenues, and are not included in the average product prices.
A three-year summary of gas related information follows:
1994 1993 1992
--------------------------------------------------------
Proved reserves at
year end (MMCF) 778,950 691,530 372,223
Gas revenues (millions) $174.5 $159.2 $134.2
Average gas price per MCF* $1.97 $2.10 $1.81
Average daily
production (MMCF) 247.6 211.1 204.6
Gas sales as a % of
oil and gas sales 59% 59% 53%
<FN>
*The above amount reflects a reduction of $.048 per MCF in 1993 and $.045 per
MCF in 1992 from hedging.
(This page contained two graphs in the body of the text: Gas Revenues for
three years and Oil Revenues for three years)
Page 17
CRUDE OIL INFORMATION
Oil sales for 1994 increased 10 percent to $122.9 million from $111.3
million in 1993. Oil sales for 1993 decreased 7 percent from $120.2 million
in 1992. Average daily production increased 17 percent to 22,751 barrels from
19,496 barrels in 1993 and 9 percent in 1993 from 17,826 barrels in 1992.
Offsetting the benefit of the production increases was a decrease in average
oil prices for 1994 and 1993 of 6 percent and 15 percent, respectively.
Average oil price decreased to $14.90 per barrel in 1994 from the $15.91
per barrel average price in 1993 and from $18.68 per barrel in 1992. The
Company believes prices should improve moderately over time, but when
conditions warrant, price hedging may be used to minimize exposure to price
volatility. The Company's oil revenues in 1993 and 1992 include approximately
$100,000 and $2.1 million of hedging income, respectively, which increased
the average oil price for 1993 by $.02 per barrel, and for 1992 by $.33 per
barrel. The Company did not hedge any of its oil production during 1994 and
had no hedged positions outstanding at year end.
International sales accounted for 16 percent of 1994 oil sales. During
1993 and 1992, international oil sales accounted for 19 percent and 23
percent of oil sales, respectively. Average daily oil production from
properties outside the United States was 3,329 barrels in 1994, 3,465 barrels
in 1993, and 4,194 barrels in 1992. It is anticipated that international
sales in 1995 will not vary significantly from 1994 levels.
A three-year summary of oil related information follows:
1994 1993 1992
-----------------------------------------------------------
Proved reserves at
year end (thousands of barrels)
Working interest 73,147 70,245 45,400
Royalty interest (1) 2,380 2,710 1,980
-----------------------------------------------------------
Total 75,527 72,955 47,380
-----------------------------------------------------------
-----------------------------------------------------------
Oil revenues (millions) $122.9 $111.3 $120.2
Average oil price
per barrel (2) $14.90 $15.91 $18.68
Average daily
production (barrels) 22,751 19,496 17,826
Oil sales as a % of
oil and gas sales 41% 41% 47%
<FN>
(1) Includes royalty oil, condensate and gas reserves stated in BOE's.
(2) Includes $.02 per barrel in 1993 and $.33 per barrel in 1992 from
hedging income.
COSTS AND EXPENSES
In 1994, oil and gas exploration expense increased $17.8 million over 1993
to $54.3 million. The increase resulted from a $21.3 million increase in dry
hole expense in 1994, which was partially offset by a $4.3 million decrease
in undeveloped lease amortization. Dry hole expense increased as a result of
higher exploration activity during 1994. In 1993, oil and gas exploration
expense increased $7.5 million over 1992 to $36.5 million. The 1993 increase
resulted from a $2.3 million increase in dry hole expense, a $1.7 million
increase in undeveloped lease amortization and a $4.2 million increase in
abandoned assets.
In 1994, oil and gas operations expense decreased $.4 million from 1993 to
$74.7 million. This decrease occurred in spite of increased oil and gas
production, and can be explained by several factors: (1) International
operations expense in 1994 decreased approximately $3 million due to the sale
of the Company's Camar property in Indonesia, as well as lower operating
costs incurred in the Company's remaining international operations. (2) In
the fourth quarter of 1993, operations expense reflected expenses being
charged to the Company on acquired properties. In 1994, the Company absorbed
the operations for these acquired properties with little incremental cost,
resulting in limited increases in operations expense notwithstanding
increased production. (3) In 1994, the Company incurred fewer workover
expenses, thereby reducing operations expense from 1993 levels.
(This page contained two graphs in the body of the text: Net Income for three
years and Average Production and Lifting Cost Per BOE for three years)
Page 18
In 1993, oil and gas operations expense increased $6.7 million over 1992 to
$75.1 million. Approximately $3.6 million of the 1993 increase was attributable
to properties purchased during 1993.
In 1994, DD&A expense increased $20.3 million over 1993 to $127.5 million.
This increase resulted primarily from higher oil and gas production volumes
predominantly from properties acquired in late 1993, along with a $6.8
million increase due to reserve writedowns on three offshore Louisiana blocks
and approximately $3 million on other properties. DD&A expense for 1993
increased $12.4 million over 1992 to $107.2 million. In 1993, DD&A expense
associated with acquired properties was $15.2 million, and $4.7 million was
due to a reserve writedown on the Company's Camar property in Indonesia. The
unit rate of DD&A expense per BOE, converting gas to oil on a 6:1 basis, was
$5.46 for 1994, $5.37 for 1993 and $5.00 for 1992.
The Company provides for the cost of future liabilities related to
restoration and dismantlement costs for offshore facilities. This provision
is based on the Company's best estimate of such costs to be incurred in
future years based on information from the Company's engineers. These
estimated costs are provided through DD&A expense using a ratio of production
divided by reserves multiplied by the estimated costs to dismantle and
restore. The Company has provided $31.1 million for such future costs which
are classified in accumulated DD&A on the balance sheet. Total estimated
future dismantlement and restoration costs of $71.4 million are included in
future production and development costs for purposes of estimating the future
net revenues relating to the Company's proved reserves.
In 1994, selling, general and administrative (SG&A) expense increased $4.6
million over 1993 to $36.4 million. This increase was due, in part, to the
start-up operations of the Company's marketing subsidiary, which sustained
$1.2 million in SG&A expense in 1994, along with $2.2 million for various
divisions which hired additional personnel to oversee increased operations.
In 1993, SG&A expense increased $686,000 over 1992 to $31.8 million. The 1993
increase was due to personnel relocation expenses as the result of closing
the Midland, Texas office.
INTEREST EXPENSE
In 1994, interest expense increased $4.3 million over 1993 to $24.7
million. This increase was due, in part, to recognizing a full year's
interest on the Company's $330 million of notes issued in late 1993, which
caused an increase of $13.7 million. Offsetting the increase was a decrease
of $7.4 million attributable to redemption in June 1994 of the Company's
$125,000,000 10 1/8% Notes Due June 1, 1997 and an additional decrease of
$2.5 million resulted from redemption in May 1993 of the Company's
$100,000,000 7 1/4% Convertible Debentures Due 2012. Interest expense in 1993
of $20.4 million remained flat with 1992 levels.
In 1994, capitalized interest increased $2.1 million over 1993 to $7.2
million. This increase is primarily due to a $1.4 million increase in
interest capitalized on East Cameron blocks 320, 331 and 332 which were
acquired during 1993 and in which development was completed during 1994. In
1993, capitalized interest increased $3.8 million over 1992 to $5.1 million.
The 1993 increase was primarily due to interest capitalization on these
properties.
(This page contained two graphs in the body of the text: DD&A Expense Per BOE
of Production for three years and SG&A Expense Per BOE of Production for
three years)
Page 19
MARKETING SUBSIDIARY
In June 1994, NGM began marketing the Company's natural gas as well as
third-party gas. NGM's business plan calls for it to sell gas directly to
end-users, gas marketers, industrial users, interstate and intrastate gas
pipelines, and local distribution companies. The Company records all of NGM's
sales as gathering, marketing and processing revenues. All inter- company
sales and costs have been eliminated.
In 1994, NGM recorded $43.9 million in gathering, marketing and processing
revenues and $42.8 million in gathering, marketing and processing expenses,
generating a gross margin of $1.1 million for the year. The gross margin was
offset by administrative expenses of $1.2 million, resulting in a loss for
NGM's initial year of operations.
FUTURE TRENDS
The Company's oil and gas production capabilities have increased during
1994 as a result of development of new properties in the Gulf of Mexico.
Despite lower natural gas prices, the Company expects its average daily
production to increase in 1995 over 1994.
Other income would increase during 1995 if the Company receives a
settlement from Columbia Gas Transmission Corporation (Columbia). Samedan Oil
Corporation (Samedan), a wholly owned subsidiary of the Company, is an
unsecured creditor of Columbia, which filed for protection from creditors
under Chapter 11 of the Federal Bankruptcy Code on July 31, 1991. Samedan and
Columbia are parties to a gas sales contract which was rejected by Columbia
in its bankruptcy proceeding. On March 16, 1992, Samedan filed a proof of
claim with the bankruptcy court in the amount of approximately $117 million
covering approximately $3 million for the contract price on prepetition gas
purchases, approximately $2 million for the contract price due on prepetition
take or pay obligations and approximately $112 million for damages arising
from the rejection of Samedan's gas sales contract. The full amount of
Samedan's claim is classified as an unsecured claim.
Except for the $3 million receivable recorded for prepetition gas
purchased by Columbia, the Company's financial statements do not reflect any
other receivables from Columbia relative to the Company's claims. It is
unknown whether resolution of Samedan's claim will occur in 1995, or at what
amount the ultimate resolution of the claims may be settled.
The Company recently set its 1995 capital budget at $206 million. During
1994, the Company spent $166.1 million in capital expenditures. The Company
plans an active exploration and development program in its domestic onshore
and offshore divisions along with its Canadian and Tunisian operations. Such
capital budget and exploration expenditures are planned to be funded through
internally generated cash flows.
Management believes that the Company is well positioned with its balanced
reserves of oil and gas to take advantage of future price increases that may
occur. However, the uncertainty of oil and gas prices continues to affect the
domestic oil and gas industry. Due to the volatility of oil and gas prices,
the Company, from time to time, has used hedging and plans to do so in the
future as a means of controlling its exposure to price changes.
Spot gas prices in early 1995 have decreased from the prior year's prices
primarily as a result of mild winter conditions in much of the United States,
while oil prices have increased slightly as a result of worldwide demand.
The Company cannot predict the extent to which its revenues will be affected
by inflation, government regulation or changing prices.
Page 20
SELECTED FINANCIAL DATA NOBLE AFFILIATES, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE
AND RATIOS) 1994 1993 1992 1991 1990
--------------------------------------------------------------------------------------
REVENUES AND INCOME
Revenues $358,389 $286,583 $303,782 $250,417 $243,196
Net cash provided by operating
activities 188,621 139,381 125,107 89,179 107,188
Net income 3,166 12,625 41,240 19,308 28,554
PER SHARE DATA
Net income $ .06 $ .26 $ .93 $ .44 $.65
Cash dividends .16 .16 .16 .16 .16
Year end stock prices 24.75 26.50 17.63 13.63 14.13
Average shares outstanding 49,970 48,098 44,341 44,135 43,986
FINANCIAL POSITION
Property, plant and equipment,
net:
Oil and gas mineral interests,
equipment and facilities $804,009 $784,235 $409,740 $458,892 $437,363
Total assets 933,516 1,067,996 625,621 589,642 588,071
Long-term obligations:
Long-term debt 376,956 453,760 224,793 224,746 224,699
Deferred income taxes 61,802 45,108 33,378 35,227 38,172
Other 10,704 7,158 7,010 8,488 9,985
Shareholders' equity 412,066 415,432 304,779 264,509 250,851
Ratio of long-term debt to
shareholders' equity .91 1.09 .74 .85 .90
CAPITAL EXPENDITURES
Oil and gas mineral interests,
equipment and facilities $158,973 $508,506 $ 64,066 $121,378 $90,588
Other 2,371 1,607 1,744 3,970 6,766
-------------------------------------------------------------------------------------
Total capital expenditures $161,344 $510,113 $ 65,810 $125,348 $97,354
-------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------
1994 1993 1992 1991 1990
------------------------------------------------------------------------------------
GAS
Sales (in millions) $174.5 $159.2 $134.2 $111.1 $113.2
Production (MMCF per day) 247.6 211.1 204.6 178.4 158.2
Average price (per MCF) $ 1.97 $ 2.10 $ 1.81 $ 1.74 $2.00
OIL
Sales (in millions) $122.9 $111.3 $120.2 $109.2 $102.9
Production (BBLS per day) 22,751 19,496 17,826 15,001 12,856
Average price (per BBL) $14.90 $15.91 $18.68 $20.39 $22.47
Royalty sales (in millions) $ 8.8 $ 7.5 $ 5.4 $ 6.2 $ 6.8
Page 21
CONSOLIDATED BALANCE SHEET NOBLE AFFILIATES, INC. AND SUBSIDIARIES
DECEMBER 31,
-------------------------------------------------------------------------------------
(IN THOUSANDS OF DOLLARS) 1994 1993
-------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS:
Cash and short-term cash investments $ 22,192 $ 176,432
Accounts receivable - trade 49,692 66,314
Materials and supplies inventories 3,591 3,302
Other current assets 28,412 10,516
-------------------------------------------------------------------------------------
Total current assets 103,887 256,564
-------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT AT COST:
Oil and gas mineral interests, equipment and facilities
(successful efforts method of accounting) 1,560,392 1,460,937
Other 28,067 26,131
------------------------------------------------------------------------------------
1,588,459 1,487,068
Accumulated depreciation, depletion and amortization (775,079) (692,463)
-------------------------------------------------------------------------------------
Total property, plant and equipment, net 813,380 794,605
-------------------------------------------------------------------------------------
OTHER ASSETS 16,249 16,827
-------------------------------------------------------------------------------------
$ 933,516 $1,067,996
-------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - trade $ 46,473 $ 29,354
Other current liabilities 21,747 19,241
Short-term borrowing 95,600
Income taxes - current 3,768 2,343
-------------------------------------------------------------------------------------
Total current liabilities 71,988 146,538
-------------------------------------------------------------------------------------
DEFERRED INCOME TAXES 61,802 45,108
-------------------------------------------------------------------------------------
OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES 10,704 7,158
-------------------------------------------------------------------------------------
LONG-TERM DEBT 376,956 453,760
-------------------------------------------------------------------------------------
SHAREHOLDER'S EQUITY:
Preferred stock - par value $1; 4,000,000 shares
authorized, none issued Common stock - par value $3.33 1/3;
100,000,000 shares authorized; 51,537,455 and 51,461,122
shares issued in 1994 and 1993, respectively 171,790 171,535
Capital in excess of par value 141,911 140,703
Retained earnings 113,783 118,612
-------------------------------------------------------------------------------------
427,484 430,850
Less common stock in treasury, at cost (1994 and 1993,
1,524,900 shares) (15,418) (15,418)
-------------------------------------------------------------------------------------
Total shareholders' equity 412,066 415,432
-------------------------------------------------------------------------------------
$ 933,516 $1,067,996
-------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 22
CONSOLIDATED STATEMENT OF OPERATIONS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1994 1993 1992
-------------------------------------------------------------------------------------
REVENUES:
Oil and gas sales and royalties $306,169 $278,004 $259,765
Gathering, marketing and processing 43,921
Other income 8,299 8,579 44,017
-------------------------------------------------------------------------------------
358,389 286,583 303,782
-------------------------------------------------------------------------------------
COSTS AND EXPENSES:
Oil and gas exploration 54,321 36,473 28,950
Oil and gas operations 74,661 75,110 68,371
Gathering, marketing and processing 42,758
Depreciation, depletion and amortization 127,470 107,215 94,819
Selling, general and administrative 36,408 31,784 31,098
Interest 24,729 20,402 20,482
Interest capitalized (7,183) (5,060) (1,260)
------------------------------------------------------------------------------------
353,164 265,924 242,460
------------------------------------------------------------------------------------
INCOME BEFORE TAXES 5,225 20,659 61,322
------------------------------------------------------------------------------------
INCOME TAX PROVISIONS:
Current (10,462) 558 18,816
Deferred 12,521 7,476 1,266
------------------------------------------------------------------------------------
2,059 8,034 20,082
------------------------------------------------------------------------------------
NET INCOME $ 3,166 $ 12,625 $ 41,240
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
NET INCOME PER SHARE $.06 $.26 $.93
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
AVERAGE NUMBER SHARES OUTSTANDING 49,970 48,098 44,341
------------------------------------------------------------------------------------
------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 23
CONSOLIDATED STATEMENT OF CASH FLOWS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------
(IN THOUSANDS OF DOLLARS) 1994 1993 1992
------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,166 $ 12,625 $41,240
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 127,470 107,215 94,819
Amortization of undeveloped lease costs, net 7,813 12,063 10,352
Gain on sale of investment in unconsolidated
affiliate (27,956)
Gain on sale of marketable securities (849)
Loss on disposal of assets 2,213 4,821 1,455
Noncurrent deferred income taxes 16,694 11,730 (1,849)
Increase (decrease) in other deferred credits 3,546 148 (1,478)
Decrease in other assets 8,232 3,744 3,676
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable 16,622 (4,445) 2,892
(Increase) decrease in other current assets (18,185) (5,789) 3,816
Increase (decrease) in accounts payable 17,119 (194) (6,571)
Increase (decrease) in other current liabilities 3,931 (2,537) 5,560
-----------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 188,621 139,381 125,107
-----------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (166,121) (508,506) (66,365)
Proceeds from sale of property, plant and
equipment 2,392 10,606 9,164
Proceeds from sale of investment in
unconsolidated affiliate 49,100
Proceeds from sale of marketable securities 1,454
-----------------------------------------------------------------------------------
NET CASH USED IN INVESTING ACTIVITIES (163,729) (497,900) (6,647)
-----------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
(Retirement of) proceeds from issuance of
long-term debt (125,000) 324,589
(Retirement of) proceeds from short-term debt
for property acquisition (95,600) 95,600
Proceeds from bank borrowings 48,000
Exercise of stock options 1,463 5,647 6,122
Cash dividends paid (7,995) (7,766) (7,092)
Cash redemption of convertible debt (1,845)
-----------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (179,132) 416,225 (970)
-----------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH
INVESTMENTS (154,240) 57,706 117,490
CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING
OF YEAR 176,432 118,726 1,236
-----------------------------------------------------------------------------------
CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR $ 22,192 $ 176,432 $118,726
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $ 18,603 $ 13,335 $ 18,933
Income taxes $ 660 $ 5,300 $ 19,667
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Page 24
CONSOLIDATED STATEMENT OF NOBLE AFFILIATES, INC. AND SUBSIDIARIES
SHAREHOLDERS' EQUITY
COMMON STOCK CAPITAL IN TREASURY
------------ EXCESS OF STOCK AT RETAINED
(IN THOUSAND OF DOLLARS) SHARES AMOUNT PAR VALUE COST EARNINGS
-------------------------------------------------------------------------------------------
JANUARY 1, 1992 45,720,323 $152,399 $47,923 $(15,418) $79,605
-------------------------------------------------------------------------------------------
Net Income 41,240
Exercise of stock options 412,019 1,373 4,749
Cash dividends ($ .16 per share) (7,092)
-------------------------------------------------------------------------------------------
DECEMBER 31, 1992 46,132,342 $153,772 $52,672 $(15,418) $113,753
-------------------------------------------------------------------------------------------
Net Income 12,625
Exercise of stock options 327,407 1,092 4,555
Redemption of convertible debentures 5,001,373 16,671 83,476
Cash dividends ($ .16 per share) (7,766)
-----------------------------------------------------------------------------------------------
DECEMBER 31, 1993 51,461,122 $171,535 $140,703 $(15,418) $118,612
-----------------------------------------------------------------------------------------------
Net Income 3,166
Exercise of stock options 76,333 255 1,208
Cash dividends ($ .16 per share) (7,995)
-----------------------------------------------------------------------------------------------
DECEMBER 31, 1994 51,537,455 $171,790 $141,911 $(15,418) $113,783
-----------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLAR AMOUNTS IN TABLES, UNLESS OTHERWISE INDICATED, ARE IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS.)
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION
The consolidated accounts include Noble Affiliates, Inc. (the Company) and
the consolidated accounts of its wholly owned subsidiaries: Samedan Oil
Corporation (Samedan) and Noble Gas Marketing, Inc. (NGM). Samedan's
consolidated accounts include the following wholly owned subsidiaries:
Samedan Oil of Canada, Inc.; Samedan Oil of Indonesia, Inc.; Samedan of North
Africa, Inc.; Samedan Pipe Line Corporation; Samedan Royalty Corporation; and
Samedan of Tunisia, Inc. NGM's consolidated accounts also include Noble Gas
Pipeline, Inc. All significant intercompany transactions and balances have
been eliminated.
FOREIGN CURRENCY TRANSLATION
The U.S. dollar is considered the functional currency for each of the
Company's international operations with the exception of Canada. The
functional currency for the Canadian subsidiary is the Canadian dollar which
has been translated into the U.S. dollar for the financial statements.
Translation gains or losses were not material in any of the periods presented.
Page 25
INVENTORIES
Materials and supplies inventories consisting principally of tubular goods
and production equipment are stated at the lower of cost or market, with cost
being determined by the first-in, first-out method.
PROPERTY, PLANT AND EQUIPMENT
The Company accounts for oil and gas properties under the successful
efforts method of accounting. Under this method, costs to acquire mineral
interests in oil and gas properties, to drill and equip exploratory wells
that find proved reserves and to drill and equip development wells are
capitalized. Capitalized costs of producing oil and gas properties are
amortized to operations by the unit-of-production method based on proved
developed oil and gas reserves allocated property by property as estimated by
Company engineers. Estimated future restoration and abandonment costs are
recorded by charges to depreciation, depletion and amortization expense over
the productive lives of the related properties. The Company has provided
$31.1 million for such future costs classified with accumulated DD&A in the
balance sheet. The total estimated future dismantlement and restoration costs
of $71.4 million are included in future production and development costs for
purposes of estimating the future net revenues relating to the Company's
proved reserves. Upon sale or retirement of depreciable or depletable
property, the cost and related accumulated DD&A are eliminated from the
accounts and the resulting gain or loss is recognized.
Undeveloped oil and gas properties, which are individually significant,
are periodically assessed for impairment of value and a loss is recognized at
the time of impairment by providing an impairment allowance. Other
undeveloped properties are amortized on a composite method based on the
Company's experience of successful drilling and average holding period.
Geological and geophysical costs, delay rentals and costs to drill
exploratory wells which do not find proved reserves are expensed.
Repairs and maintenance are charged to expense as incurred. Renewals and
betterments are capitalized.
INCOME TAXES
The Company files a consolidated federal income tax return. Deferred
income taxes are provided for temporary differences between the financial
reporting and tax bases of the Company's assets and liabilities.
NET INCOME PER SHARE
Net income per share of common stock has been computed on the basis of the
weighted average number of shares outstanding during each period. The effect
of shares issuable upon the exercise of stock options is immaterial. The
convertible subordinated notes, which are not common stock equivalents, have
not been included in computing fully diluted earnings per share since their
inclusion would be antidilutive.
CAPITALIZATION OF INTEREST
The Company capitalizes interest costs associated with the acquisition or
construction of significant oil and gas properties.
STATEMENT OF CASH FLOWS
For purposes of reporting cash flows, cash and short-term cash investments
include cash on hand and investments purchased with original maturities of
three months or less.
REVENUE RECOGNITION AND GAS IMBALANCES
Samedan has a gas sales contract with NGM, whereby Samedan is paid an
index price for all gas sold to NGM. NGM records sales, including hedging
transactions, as gathering, marketing and processing revenues. NGM records as
cost of sales in gathering, marketing and processing costs, the amount paid
to Samedan and third parties. All inter-company sales and costs have been
eliminated.
The Company follows an entitlements method of accounting for its gas
imbalances. Gas imbalances occur when the Company sells more or less gas than
its entitled ownership percentage of total gas production. Any excess amount
received above the Company's share is treated as a liability. If less than
the Company's entitlement is received, the underproduction is recorded as a
receivable. The Company records the noncurrent liability in Other Deferred
Credits and Noncurrent Liabilities, and the current liability in Other
Current Liabilities. The Company's gas imbalance liabilities were $10.5
million and $7.6 million for 1994 and 1993, respectively. The Company records
the noncurrent receivable in Other Assets, and the current receivable in
Other Current Assets. The Company's gas imbalance receivables were $11.7
million and $12.9 million for 1994 and 1993, respectively, and are valued at
the amount which is expected to be received.
Page 26
TAKE-OR-PAY SETTLEMENTS
The Company records gas contract settlements which are not subject to
recoupment in Other Income when the settlement is received.
TRADING AND HEDGING ACTIVITIES
The Company uses oil and gas swap agreements to hedge both fixed term
sales and sales of its oil and gas production in order to obtain a fixed
margin and minimize price risk. Under the swap agreements, the Company
receives or makes payments based on the differential between a specified
price and the actual price of oil and gas. At December 31, 1994, the Company
had six swap transactions for January 1995 with broker-dealers that
represented approximately 38,000 MMBTU of gas per day with prices ranging
from $1.50 to $1.59 per MMBTU. The Company also had three swaps for January
through November 1995 with broker-dealers that relate to term contract sales
for approximately 9,000 MMBTU of gas per day at $1.63 per MMBTU. During the
second half of 1994, the Company hedged approximately 11 percent of its
average daily gas production at prices ranging from $1.33 to $1.92 per MMBTU.
The Company had no outstanding oil hedge positions at year-end 1994 and
hedged none of its 1994 oil production. During 1994, the Company recorded
trading and hedging gains or losses in gathering, marketing and processing
revenues in the period the related contract was completed. In 1993 and 1992,
hedging gains or losses were recorded in oil and gas sales.
NOTE 2 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments pursuant to the requirements of
Statements of Financial Accounting Standards (SFAS) No. 107, "Disclosures
about Fair Value of Financial Instruments":
CASH AND SHORT-TERM CASH INVESTMENTS
The carrying amount approximates fair value due to the short maturity of
the instruments.
OIL AND GAS PRICE SWAP AGREEMENTS
The fair value of oil and gas price swaps (used for hedging purposes) is
the estimated amount the Company would receive or pay to terminate the swap
agreements at the reporting date, taking into account the difference between
year-end oil and gas prices and the fixed swap price and the creditworthiness
of the swap parties.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on the
quoted market prices for the same or similar issues or on the current rates
offered to the Company for debt of the same remaining maturities.
The carrying amounts and estimated fair values of the Company's financial
instruments are as follows:
1994 1993
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------------------------------------------------------------------------------
Cash and short-term cash investments $ 22,192 $22,192 $176,432 $176,432
Oil and gas price swap agreements $ 56
Long-term debt $376,956 $321,325 $453,760 $453,221
NOTE 3 - DEBT
A summary of debt at December 31 follows:
1994 1993
----------------------------------------------------------------------
4 1/4% Convertible Subordinated
Notes Due 2003 $230,000 $230,000
7 1/4% Notes Due 2023 100,000 100,000
Bank Credit Agreement 48,000
10 1/8% Notes Due June 1, 1997 125,000
Short-term borrowing 95,600
-----------------------------------------------------------------------
378,000 550,600
Less: unamortized discount 1,044 1,240
short-term borrowing 95,600
-----------------------------------------------------------------------
Total long-term debt $376,956 $453,760
-----------------------------------------------------------------------
-----------------------------------------------------------------------
In October 1993, the Company issued $230,000,000 4 1/4% Convertible
Subordinated Notes Due 2003 which are convertible into common stock of the
Company, at any time prior to maturity, at $36.65 per share. The securities
are subordinated to all present and future senior indebtedness. The Company,
at its election on or after November 1, 1996, may redeem these Notes in whole
or in part at 102.975 percent of the principal amount. The call premium
percentage decreases, beginning November 1, 1997, and each year thereafter
until 2003 when these Notes are redeemable at par value plus accrued interest.
Page 27
In October 1993, the Company issued $100,000,000 7 1/4% Notes Due 2023.
The Company may not redeem any portion of these Notes prior to maturity. The
indenture governing these Notes contains certain restrictions as to the sale
of assets and incurrence of additional debt.
The Company borrowed $175 million on October 1, 1993 from its then
existing bank line of credit to bridge finance the acquisition of $305
million of producing properties. The proceeds from both October 1993 debt
issues were used to repay in full the bank debt on October 21, 1993.
The Company has a line of credit agreement with certain banks which
provides for maximum unsecured borrowings of $100 million at variable rates.
The Company borrowed $48 million on June 1, 1994, and used the proceeds plus
available cash balances to redeem its $125,000,000 10 1/8% Notes Due June 1,
1997. No other borrowings have occurred against the line of credit. The
interest rate is a variable rate based on the lower of one of three interest
rate options. The weighted average interest rate on the borrowings during
1994 was 5 percent. There is a facility fee of $187,500 per year. The
agreement contains covenants including maintenance of certain financial
ratios, net worth requirements and restrictions of additional borrowings. The
bank credit agreement matures on May 31, 1997.
During the next five years, no principal payments on long-term debt are
required except for the $48 million outstanding against the bank debt, which
is due May 31, 1997.
In conjunction with the acquisition of certain producing properties from
Freeport-McMoRan, the Company issued a short-term installment note for $95.6
million on October 1, 1993. On January 4, 1994, the Company paid the
installment note including accrued interest.
On May 10, 1993, the Company called its $100,000,000 7 1/4% Convertible
Debentures Due 2012. As a result of the call for redemption, owners of
$98,155,000 of the debentures elected to convert into a total of 5,001,373
shares of common stock. The debentures were converted into shares of the
Company's common stock at $19 5/8 per share. The remaining $1,845,000 was
redeemed with cash at 103.63 percent of the principal amount, plus accrued
interest to the redemption date.
NOTE 4 - INCOME TAXES
Effective January 1, 1993, the Company adopted the provisions of SFAS No.
109, "Accounting for Income Taxes." SFAS No. 109 replaced SFAS No. 96, of
the same title, which the Company previously used to account for income
taxes. The primary difference between SFAS No. 109 and SFAS No. 96 is to
permit, under certain circumstances, the recognition of deferred tax benefits
that were not recognized under SFAS No. 96. The effect of adopting SFAS No.
109 was not material to the Company's financial statements. The Company's
financial statements for 1992 were not restated to apply the provisions of
SFAS No. 109.
The components of income from operations before income taxes for each year
are as follows:
1994 1993 1992
-------------------------------------------------
Domestic $12,148 $ 39,564 $ 78,155
Foreign (6,923) (18,905) (16,833)
-------------------------------------------------
$ 5,225 $ 20,659 $ 61,322
-------------------------------------------------
-------------------------------------------------
The income tax provisions relating to operations for each year consist of
the following:
1994 1993 1992
-------------------------------------------------
U.S. current $(10,462) $ 327 $18,566
U.S. deferred 13,140 7,701 931
State current 231 250
State deferred (31) 85 8
Foreign current
Foreign deferred (588) (310) 327
-------------------------------------------------
$2,059 $8,034 $20,082
-------------------------------------------------
-------------------------------------------------
The effect of the federal corporate tax rate increase in 1993 to 35
percent resulted in an increase in the U.S. deferred tax provision and
related liability of $1.1 million which is reflected in the above table.
Page 28
The net current deferred tax asset in the following table is classified as
Other Current Assets in the Consolidated Balance Sheet at December 31, 1994
and 1993. The tax effects of temporary differences which gave rise to
deferred tax assets and liabilities as of December 31 were:
1994 1993
-----------------------------------------------------
U.S. and State Current Deferred
Tax Assets:
Accrued expenses $ 743 $ 554
Deferred income (49) 100
Minimum tax 3,655 624
Other 751 (351)
-----------------------------------------------------
Net current deferred tax asset 5,100 927
-----------------------------------------------------
U.S. and State Non-current
Deferred Tax Liabilities:
Property, plant and equipment,
principally due to differences
in depreciation, amortization,
lease impairment and
abandonments (62,050) (45,841)
Income tax accruals 690 906
Other (442) 415
-----------------------------------------------------
Net non-current
deferred liability (61,802) (44,520)
------------------------------------------------------
U.S. and state net
deferred tax liability (56,702) (43,593)
------------------------------------------------------
Foreign Deferred Tax Liabilities:
Property, plant and equipment of
foreign operations 7,532 5,929
Net operating loss carryforwards
due to foreign operations 2,817
------------------------------------------------------
Foreign deferred asset 7,532 8,746
Valuation allowance (7,532) (9,334)
------------------------------------------------------
Deferred tax liability (588)
------------------------------------------------------
Total deferred taxes $(56,702) $(44,181)
------------------------------------------------------
------------------------------------------------------
A valuation allowance of $7,532,000 and $9,334,000 for 1994 and 1993,
respectively, related to the Company's foreign operations, was established
for the portion of the deferred tax assets which management believes is
unlikely to have a tax benefit realized.
At December 31, 1993, the Company had foreign net operating loss
carryforwards of $6.3 million that had no expiration dates. These loss
carryforwards were fully utilized in 1994.
Prior to the change in the method of accounting for income taxes discussed
above, the sources of deferred tax items and the corresponding tax effects
for the year ended December 31, 1992 were as follows:
1992
---------------------------------------------------------------------------
Capitalized intangible development costs expensed for
tax purposes in excess of book dry hole expense $ 9,653
Excess of book over tax amortization and depletion of
capitalized intangible development and producing leasehold costs (11,941)
Interest capitalized for book purposes, expensed for tax purposes 437
Excess of book over tax amortization of undeveloped leaseholds (3,540)
Seismic costs expensed for book purposes, capitalized for tax (1,423)
Disposal of assets book/tax difference 4,681
Accrued expenses 2,015
Insurance proceeds reported for book in excess of tax 1,510
Other, net (126)
---------------------------------------------------------------------------
$ 1,266
---------------------------------------------------------------------------
---------------------------------------------------------------------------
The following table details the difference between the federal statutory
tax rate and the effective tax rate for the years ended December 31:
(AMOUNTS EXPRESSED IN
PERCENTAGES) 1994 1993 1992
--------------------------------------------------------
Statutory rate 35.0 35.0 34.0
Effect of:
One percent rate increase on prior
year temporary differences 5.0
Percentage depletion (2.2) .6 .3
State taxes .1 1.1 .4
Net operating loss carryback 7.9
Other, net (1.4) (2.8) (2.0)
--------------------------------------------------------
Effective rate 39.4 38.9 32.7
--------------------------------------------------------
--------------------------------------------------------
Page 29
NOTE 5 - COMMON STOCK AND STOCK OPTIONS
At December 31, 1994, there were 1,210,708 shares available for grant
under the Company's 1992 Stock Option and Restricted Stock Plan and its 1988
Non-Employee Director Stock Option Plan.
Under the Company's 1992 Stock Option and Restricted Stock Plan, adopted
in January 1992, the Board of Directors may grant stock options and award
restricted stock. The Plan allows stock options to be issued at the market
price on the date of grant. The options may be exercised over a three year
period at the rate of 33 1/3% each year commencing on the first anniversary
of the grant date and expiring ten years from the grant date. The plan covers
a maximum of 2,000,000 shares of the Company's authorized but unissued common
stock. At December 31, 1994, the Company had reserved 1,957,942 shares of its
common stock for issuance under its 1992 stock option plan.
The Company's 1988 Non-Employee Director Stock Option Plan, adopted in
July 1988, allows stock options to be issued at the market price on the date
of grant. The options may be exercised one year after issue and expire ten
years from the grant date. The Plan provides for the grant of options to
purchase a maximum of 250,000 shares of the Company's authorized but unissued
common stock. At December 31, 1994, the Company had reserved 179,500 shares
of its common stock for issuance under its 1988 stock option plan.
Stock options outstanding under the Plans mentioned above and two
previously terminated plans are presented for the periods indicated.
NUMBER OPTION
OF SHARES PRICE RANGE
--------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1991 1,394,907 $10.63-$17.47
--------------------------------------------------------------
Granted 368,825 $15.00-$16.88
Exercised (414,502) $10.63-$17.47
Cancelled (64,282) $10.63-$17.47
--------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1992 1,284,948 $10.63-$17.47
--------------------------------------------------------------
Granted 271,224 $24.63-$24.88
Exercised (337,407) $10.63-$17.47
Cancelled (14,817) $10.88-$17.47
--------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1993 1,203,948 $10.63-$24.88
--------------------------------------------------------------
Granted 303,243 $27.25-$30.00
Exercised (76,333) $10.63-$24.88
Cancelled (1,476) $13.75-$16.88
--------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1994 1,429,382 $10.63-$30.00
--------------------------------------------------------------
EXERCISABLE AT DECEMBER 31, 1994 853,257 $10.63-$24.88
--------------------------------------------------------------
NOTE 6 - EMPLOYEE BENEFIT PLANS
PENSION PLAN
The Company has a non-contributory defined benefit pension plan covering
substantially all of its domestic employees. The benefits are based on an
employee's years of service and average earnings for the 60 consecutive
calendar months of highest compensation. The Company also has an unfunded
restoration plan to ensure payments of amounts for which employees are
entitled under the provisions of the pension plan, but which are subject to
limitations imposed by federal tax laws. The Company's funding policy has
been to make annual contributions equal to the actuarially computed liability
to the extent such amounts are deductible for income tax purposes. Plan
assets consist principally of equity securities and fixed income investments.
The periodic pension expense included the following components for the
years ended December 31:
1994 1993 1992
------------------------------------------------------------
Service cost-benefits
earned in the period $ 1,814 $ 1,388 $ 1,150
Interest cost on projected
benefit obligation 2,876 2,611 2,453
Actual return on plan assets 1,346 (4,411) (2,695)
Net amortization and deferral (4,200) 1,428 (71)
------------------------------------------------------------
Net pension expense $ 1,836 $ 1,016 $ 837
------------------------------------------------------------
------------------------------------------------------------
The funded status of the plans at December 31 was as follows:
1994 1993
FUNDED UNFUNDED FUNDED UNFUNDED
------------------------------------------------------------------------
Actuarial present value of:
Vested benefit obligation $25,037 $ 2,447 $26,988 $ 2,186
Accumulated benefit
obligation 27,307 2,620 29,362 2,298
------------------------------------------------------------------------
Projected benefit obligation 35,468 3,890 38,654 3,677
Plan assets at fair value 35,810 38,789
------------------------------------------------------------------------
Plan assets in excess of
(less than) projected
benefit obligation 342 (3,890) 135 (3,677)
Unrecognized net (gain)
loss (4,527) (176) (2,996) 960
Unrecognized net (asset)
liability at transition (2,367) 3,727 (2,582) 2,539
Unrecognized prior
service cost 2,242 1,952
------------------------------------------------------------------------
Accrued pension cost $(4,310) $ (339) $(3,491) $(178)
------------------------------------------------------------------------
------------------------------------------------------------------------
Page 30
The Company's assumptions as of December 31 in determining the pension
cost and liability for the three years were as follows:
(AMOUNTS EXPRESSED IN
PERCENTAGES) 1994 1993 1992
----------------------------------------------------
Discount rate 8.5 7.0 8.5
Rates of increase in compensation 6.0 5.0 6.0
Long-term rate of
return on plan assets 8.5 8.5 8.5
EMPLOYEE SAVINGS PLAN
The Company has an employee savings plan (ESP) which is a defined
contribution plan. Participation in the ESP is voluntary and all regular
employees of the Company are eligible to participate after one year of
employment. Subject to certain limitations, the Company may contribute up to
100 percent of the participant's contribution. The Company charged to expense
plan contributions of $775,000, $755,000 and $673,000 for 1994, 1993 and
1992, respectively.
OTHER EMPLOYEE PLANS
The Company sponsors other plans for the benefit of its employees and
retirees. These plans include health care and life insurance benefits.
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other than Pensions." The Company
recorded a cumulative catch-up adjustment for the accumulated postretirement
transition obligation of approximately $1,003,000. The net 1994 and 1993
annual postretirement benefit costs were approximately $253,000 and $173,000,
respectively.
The accumulated postretirement benefit obligation was computed using an
assumed discount rate of 8.5 percent in 1994 and 7 percent in 1993. The
health care cost trend rate was assumed to be 12 percent for 1994, declining
by one percent for six successive years to 6 percent in 2000, decreasing to
5.5 percent for 2002 and remaining at that rate thereafter.
If the health care cost trend rate was increased one percent for all
future years, the accumulated postretirement benefit obligation as of
December 31, 1994, would have increased approximately $450,000. The effect of
this change on the aggregate of service and interest cost for 1994 would have
been an increase of approximately $65,000.
Net postretirement benefit cost for the years ended December 31 includes
the following components:
1994 1993
----------------------------------------------------
Service cost - benefits earned
in the period $136 $ 91
Interest costs - accumulated
benefit obligation 93 82
Net loss amortization 24
Cumulative catch up 1,003
----------------------------------------------------
Net postretirement benefit cost $253 $1,176
----------------------------------------------------
----------------------------------------------------
The plan's postretirement benefit obligation at December 31 was as follows:
1994 1993
-----------------------------------------------------
Accumulated postretirement
benefit obligation:
Retirees $ (152) $ (223)
Fully eligible active employees (170) (140)
Active employees, not fully
eligible (854) (845)
-----------------------------------------------------
Total participants (1,176) (1,208)
Plan assets
-----------------------------------------------------
Funded status (1,176) (1,208)
Unrecognized transition
obligation
Unrecognized net loss 35 169
-----------------------------------------------------
Accrued postretirement benefit
obligation $(1,141) $(1,039)
-----------------------------------------------------
-----------------------------------------------------
Page 31
NOTE 7 - MARKETING SUBSIDIARY
In June 1994, Noble Gas Marketing, Inc., a wholly owned subsidiary of the
Company, began marketing the Company's natural gas as well as third-party
gas. NGM's business plan calls for it to sell gas directly to end-users, gas
marketers, industrial users, interstate and intrastate gas pipelines, and
local distribution companies. The Company records all of NGM's sales as
gathering, marketing and processing revenues. All intercompany sales have
been eliminated.
In 1994, NGM recorded $43.9 million in gathering, marketing and processing
revenues and $42.8 million in gathering, marketing and processing expenses,
generating a gross margin of $1.1 million for the year. The gross margin was
offset by administrative expenses of $1.2 million, resulting in a loss for
NGM's initial year of operations.
NOTE 8 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION
Other current assets at December 31 include the following:
1994 1993
----------------------------------------------------
Income tax receivable $17,545 $12,759
Other current liabilities at December 31 include the following:
1994 1993
----------------------------------------------------
Gas imbalance liabilities $2,101 $1,520
Oil and gas exploration expense included the following for the years ended
December 31:
1994 1993 1992
-----------------------------------------------------------
Dry hole expense $35,275 $13,968 $11,657
Undeveloped lease amortization 7,813 12,063 10,352
Abandoned assets 2,945 6,068 1,863
Seismic 8,254 5,199 4,969
Listed below are the purchasers who accounted for more than ten percent of
total oil and gas sales and royalties in the past three years.
1994 1993 1992
----------------------------------------------------
Natural Gas Clearinghouse 16% 16% 13%
Page 32
NOTE 9 - ACQUISITIONS
The Company completed two major acquisitions of oil and gas properties
during 1993. In the first acquisition, on July 15, 1993, the Company
purchased for $100 million all of Freeport-McMoRan's interest in East Cameron
blocks 320, 331, and 332 in the Gulf of Mexico. The Company acts as operator
of these properties with an average working interest of 70 percent.
Facilities with a production capacity of 100 MMCF of gas and 10,000 BBLS of
oil per day were completed and set in 1994. Production commenced in October
1994. This acquisition was purchased with cash on hand, without additional
borrowings.
In the second acquisition, on October 1, 1993, the Company purchased for
$305 million substantially all the remaining oil and gas properties of
Freeport-McMoRan located in the Gulf of Mexico, Montana, Colorado, and
California. The Company completed two issuances of long-term debt to finance
the second acquisition.
The acquisitions of the Freeport-McMoRan properties were accounted for as
a purchase and the results of operations are included in the statement of
operations from the date of the acquisitions. The cost of the acquisitions
has been allocated on the basis of the estimated market value of the assets
acquired.
The following unaudited pro forma data includes various adjustments which
are considered necessary to properly state the amounts as though the
acquisitions had occurred at the beginning of each period shown.
1993 1992
-----------------------------------------------------
Revenues $377,532 $369,176
Net income $39,138 $42,496
Net income per share $.81 $.96
The pro forma data presented above is based on several assumptions and
should not be viewed as indicative of the operations of the Company in future
periods.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors
of Noble Affiliates, Inc.:
We have audited the accompanying consolidated balance sheet of Noble
Affiliates, Inc. (a Delaware corporation) and subsidiaries as of December 31,
1994 and 1993, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 1994. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on
these financial statements 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 Noble Affiliates, Inc.
and subsidiaries as of December 31, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles.
Oklahoma City, Oklahoma ARTHUR ANDERSEN LLP
January 27, 1995
Page 33
NOTE 10 - SUPPLEMENTAL OIL AND GAS INFORMATION
(Unaudited)
The following reserve schedules were developed by the Company's reserve
engineers and set forth the changes in estimated quantities of proved oil and
gas reserves of the Company during each of the three years presented, and the
proved developed oil and gas reserves as of the beginning of each year.
NATURAL GAS & CRUDE OIL & CONDENSATE
CASINGHEAD GAS (MMCF) (BARRELS IN THOUSANDS)
------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED AND UNITED OTHER UNITED OTHER
UNDEVELOPED RESERVES: STATES CANADA FOREIGN TOTAL STATES CANADA FOREIGN TOTAL
------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF
DECEMBER 31, 1991 373,276 20,926 2,408 396,610 38,054 1,959 3,867 43,880
------------------------------------------------------------------------------------------------------------
Revisions of previous estimates (1,450) 17 (1,433) 772 91 731 1,594
Extensions, discoveries and
other additions 42,102 7,711 49,813 5,406 462 2,172 8,040
Production (69,367) (3,926) (73,293) (5,115) (339) (1,197) (6,651)
Sale of minerals in place (1,352) (1,352) (139) (493) (632)
Purchase of minerals in place 1,157 721 1,878 980 169 1,149
-----------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF
DECEMBER 31, 1992 344,366 25,449 2,408 372,223 39,958 2,342 5,080 47,380
-----------------------------------------------------------------------------------------------------------
Revisions of previous estimates (5,811) 809 (5,002) (2,374) 168 (277) (2,483)
Extensions, discoveries and
other additions 62,479 2,131 64,610 7,285 1,410 8,695
Production (71,310) (3,829) (75,139) (6,064) (347) (950) (7,361)
Sale of minerals in place (6,903) (20) (6,923) (389) (23) (412)
Purchase of minerals in place 341,578 183 341,761 27,107 29 27,136
-----------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF
DECEMBER 31, 1993 664,399 24,723 2,408 691,530 65,523 3,579 3,853 72,955
-----------------------------------------------------------------------------------------------------------
Revisions of previous estimates 15,409 2,418 17,827 (1,052) 161 1,550 659
Extensions, discoveries and
other additions 148,008 6,773 154,781 8,160 712 1,139 10,011
Production (84,504) (3,225) (87,729) (7,434) (446) (791) (8,671)
Sale of minerals in place (854) (167) (1,021) (276) (19) (295)
Purchase of minerals in place 1,787 1,775 3,562 615 253 868
-----------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF
DECEMBER 31, 1994 744,245 32,297 2,408 778,950 65,536 4,240 5,751 75,527
-----------------------------------------------------------------------------------------------------------
PROVED DEVELOPED RESERVES:
January 1, 1992 372,100 19,981 2,408 394,489 34,000 1,501 3,867 39,368
January 1, 1993 344,366 24,504 2,408 371,278 36,938 1,884 5,080 43,902
January 1, 1994 570,462 24,723 2,408 597,593 64,284 3,032 3,853 71,169
January 1, 1995 658,228 32,297 2,408 692,933 63,013 3,693 4,612 71,318
PROVED RESERVES
Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED DEVELOPED RESERVES
Proved developed reserves are proved reserves which are expected to be
recovered through existing wells with existing equipment and operating
methods.
Page 34
COSTS INCURRED IN OIL AND GAS ACTIVITIES
Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities during the year are shown below.
Amounts are presented in accordance with SFAS No. 19, and may not agree with
amounts determined using traditional industry definitions.
1994 1993
------------------------------------------------------------------------------------------------
UNITED OTHER UNITED OTHER
STATES CANADA FOREIGN TOTAL STATES CANADA FOREIGN TOTAL
------------------------------------------------------------------------------------------------
Property
acquisition costs:
Proved $ 3,742 $2,375 $ $ 6,117 $418,087 $ 364 $ $418,451
Unproved 8,695 1,773 10,468 2,537 1,902 4,439
------------------------------------------------------------------------------------------------
Total $12,437 $4,148 $ $16,585 $420,624 $2,266 $ $422,890
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
Exploration costs $48,151 $7,293 $7,363 $62,807 $23,392 $4,708 $5,449 $33,549
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
Development costs $105,993 $2,871 $1,474 $110,338 $53,650 $4,192 $730 $58,572
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
1992
----------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
----------------------------------------------------------
Property
acquisition costs:
Proved $4,406 $1,498 $ 300 $ 6,204
Unproved 1,474 1,037 2,511
----------------------------------------------------------
Total $5,880 $2,535 $ 300 $ 8,715
----------------------------------------------------------
----------------------------------------------------------
Exploration costs $16,122 $3,351 $5,639 $25,112
----------------------------------------------------------
----------------------------------------------------------
Development costs $34,473 $2,549 $4,658 $41,680
----------------------------------------------------------
----------------------------------------------------------
AGGREGATE CAPITALIZED COSTS
Aggregate capitalized costs relating to the Company's oil and gas
producing activities, and related accumulated DD&A as of the end of the year
are shown below.
1994 1993
------------------------------------------------------------------------------------------------------------
UNITED OTHER UNITED OTHER
STATES CANADA FOREIGN TOTAL STATES CANADA FOREIGN TOTAL
------------------------------------------------------------------------------------------------------------
Unproved oil and
gas properties $ 34,254 $ 7,842 $ 3,274 $ 45,370 $ 32,941 $ 6,564 $ 3,340 $ 42,845
Proved oil and
gas properties 1,448,412 42,315 24,295 1,515,022 1,344,490 35,505 38,097 1,418,092
------------------------------------------------------------------------------------------------------------
1,482,666 50,157 27,569 1,560,392 1,377,431 42,069 41,437 1,460,937
Accumulated DD&A 722,701 23,017 10,665 756,383 631,292 19,544 25,866 676,702
------------------------------------------------------------------------------------------------------------
Net capitalized
costs $ 759,965 $27,140 $16,904 $ 804,009 $ 746,139 $22,525 $15,571 $ 784,235
-------------------------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------------------------
Page 35
OIL AND GAS OPERATIONS
Aggregate results of operations in connection with the Company's oil and
gas producing activities are shown below.
1994 1993
----------------------------------------------------------------------------------------------------------------
UNITED OTHER UNITED OTHER
STATES CANADA FOREIGN TOTAL STATES CANADA FOREIGN TOTAL
----------------------------------------------------------------------------------------------------------------
Revenues $277,467 $15,448 $13,254 $306,169 $250,636 $12,812 $14,556 $278,004
Production costs 68,340 4,072 3,128 75,540 66,507 4,150 6,084 76,741
Exploration expenses 49,991 8,874 9,373 68,238 28,927 5,662 8,333 42,922
DD&A and valuation
provision 125,880 4,153 2,373 132,406 101,609 3,549 11,396 116,554
----------------------------------------------------------------------------------------------------------------
Income (loss) 33,256 (1,651) (1,620) 29,985 53,593 (549) (11,257) 41,787
Income tax expense
(benefit) 11,503 (1,039) 1,006 11,470 19,345 (776) (3,559) 15,010
----------------------------------------------------------------------------------------------------------------
Results of operations
from producing
activities (excluding
corporate overhead
and interest costs) $21,753 $ (612) $(2,626) $18,515 $34,248 $ 227 $(7,698) $ 26,777
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
1992
--------------------------------------------------------------------
UNITED OTHER
STATES CANADA FOREIGN TOTAL
--------------------------------------------------------------------
Revenues $226,410 $11,961 $21,394 $259,765
Production costs 57,108 2,950 8,668 68,726
Exploration expenses 24,506 4,434 10,229 39,169
DD&A and valuation
provision 88,442 2,593 11,727 102,762
--------------------------------------------------------------------
Income (loss) 56,354 1,984 (9,230) 49,108
Income tax expense
(benefit) 19,170 891 (3,139) 16,922
--------------------------------------------------------------------
Results of operations
from producing
activities (excluding
corporate overhead
and interest costs) $37,184 $1,093 $(6,091) $32,186
--------------------------------------------------------------------
--------------------------------------------------------------------
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES
The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash
Flows required by Financial Accounting Standards Board's Statement of
Financial Accounting Standards No. 69. The Standard requires the use of a 10
percent discount rate. This information is not the fair market value nor does
it represent the expected present value of future cash flows of the Company's
proved oil and gas reserves.
1994 1993 1992
--------------------------------------------------------------------------------------------------------------------------
(IN MILLIONS UNITED OTHER UNITED OTHER UNITED OTHER
OF DOLLARS) STATES CANADA FOREIGN TOTAL STATES CANADA FOREIGN TOTAL STATES CANADA FOREIGN TOTAL
--------------------------------------------------------------------------------------------------------------------------
Future cash inflows $2,439 $120 $104 $2,663 $2,635 $102 $55 $2,792 $1,471 $86 $93 $1,650
Future production and
development costs 870 44 18 932 869 47 17 933 608 36 36 680
Future income tax
expenses 423 21 23 467 481 15 10 506 220 13 14 247
-------------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,146 55 63 1,264 1,285 40 28 1,353 643 37 43 723
10% annual discount for
estimated timing of
cash flows 479 23 26 528 656 13 9 678 209 12 14 235
-------------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 667 $ 32 $ 37 $ 736 $ 629 $ 27 $19 $ 675 $ 434 $25 $29 $ 488
-------------------------------------------------------------------------------------------------------------------------
Page 36
Future cash inflows are computed by applying year-end prices of oil and
gas relating to the Company's proved reserves to the year-end quantities of
those reserves, with consideration given to the effect of existing trading
and hedging contracts if any. The year-end weighted average oil price
utilized in the computation of future cash inflows was approximately $15.55
per barrel.
Oil prices at the end of February 1995 increased slightly since year end.
The Company estimates that a $1.00 per barrel change in the average oil price
from the year-end price would change discounted future net cash flows before
income taxes by approximately $44 million.
The year-end weighted average gas price utilized in the computation of
future cash inflows was approximately $1.75 per MCF. Natural gas spot prices
at the end of February 1995 decreased from year end. The Company estimates
that a $.10 per MCF change in the average gas price from the year-end price
would change discounted future net cash flows before income taxes by
approximately $47 million.
Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be
incurred in developing and producing the Company's proved oil and gas
reserves at the end of the year, based on year-end costs, and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate
year-end statutory tax rates to the future pretax net cash flows relating to
the Company's proved oil and gas reserves, less the tax bases of the
properties involved. The future income tax expenses give effect to tax
credits and allowances, but do not reflect the impact of general and
administrative cost and exploration expenses of ongoing operations relating
to the Company's proved oil and gas reserves.
At December 31, 1994, the Company had estimated gas imbalance receivables
of $11.7 million and estimated liabilities of $10.5 million; at year-end
1993, $12.9 million in receivables and $7.6 million in liabilities; and at
year-end 1992, $17.0 million in receivables and $12.8 million in liabilities.
Neither the gas imbalance receivables nor liabilities have been included in
the standardized measure of discounted future net cash flows for the three
years ended December 31, 1994.
Principal changes in the aggregate standardized measure of discounted
future net cash flows attributable to the Company's proved oil and gas
reserves at year end are shown below.
(IN MILLIONS OF DOLLARS) 1994 1993 1992
--------------------------------------------------------
Standardized measure of discounted
future net cash flows at the
beginning of the year $675 $488 $445
Extensions, discoveries and
improved recovery, less
related costs 160 89 113
Revisions of previous
quantity estimates 18 (19) 15
Changes in estimated future
development costs (31) (23) (5)
Purchases/sales of
minerals in place 3 397 4
Net changes in prices and
production costs (90) (40) 52
Accretion of discount 95 66 60
Sales of oil and gas produced,
net of production costs (228) (200) (189)
Development costs incurred
during the period 44 8 10
Net change in income taxes (17) (102) (12)
Change in timing of estimated
future production, and other 107 11 (5)
--------------------------------------------------------
Standardized measure of
discounted future net cash
flows at the end of the year $ 736 $ 675 $ 488
--------------------------------------------------------
--------------------------------------------------------
NOTE 11 - INTERIM FINANCIAL INFORMATION
(Unaudited)
Interim financial information for the two years ended December 31, 1994 is
as follows:
QUARTER ENDED
---------------------------------------------------------------
MAR. 31, JUNE 30, SEPT. 30, DEC. 31,
---------------------------------------------------------------
1994
Revenues $83,541 $92,032 $97,441 $ 85,375
Gross profit (loss)
from operations $16,351 $10,494 $ 3,877 $(13,451)
Net income (loss) $ 8,417 $ 4,377 $ 2,051 $(11,679)
Net income (loss)
per share $ .17 $ .09 $ .04 $ (.23)
1993
Revenues $69,854 $66,327 $64,346 $ 86,056
Gross profit (loss)
from operations $16,696 $ 5,041 $11,318 $ (372)
Net income (loss) $ 4,488 $ 4,002 $ 4,265 $ (130)
Net income (loss)
per share $ .10 $ .08 $ .09 $ (.01)
During the fourth quarter of 1994, DD&A expense increased by approximately
$3,100,000 relating to the cumulative effect of oil and gas reserve revisions
on the DD&A provision for the preceding three quarters.
During the fourth quarter of 1993, the cumulative effect of oil and gas
reserve revisions on the DD&A provision for the preceding three quarters was
insignificant.
Page 37
GLOSSARY
BBLS BARRELS
BCF BILLION CUBIC FEET
BOE BARREL OF OIL EQUIVALENT
LPG LIQUID PETROLEUM GAS
MCF THOUSAND CUBIC FEET
MMBBLS MILLION BARRELS
MMBTU MILLION BRITISH THERMAL UNITS
MMCF MILLION CUBIC FEET
CORPORATE INFORMATION
TRANSFER AGENT AND REGISTRAR
The Liberty National Bank
and Trust Company of
Oklahoma City
P. O. Box 25848
Oklahoma City, Oklahoma 73125
INDEPENDENT ACCOUNTANTS
Arthur Andersen LLP
Oklahoma City, Oklahoma
COMMON STOCK LISTED
New York Stock Exchange
Symbol - NBL
SHAREHOLDERS' PROFILE
December 31, 1994
SHARES SHAREHOLDERS
OUTSTANDING OF RECORD
-------------------------------------------------------
Individuals 735,181 1,210
Joint accounts 116,318 294
Fiduciaries 242,096 351
Institutions 6,999,833 50
Brokers 1,300 1
Nominees 41,904,188 7
Foreign 13,639 16
-----------------------------------------------------
Total 50,012,555 1,929
-----------------------------------------------------
-----------------------------------------------------
DIVIDEND AND STOCK PRICES BY QUARTERS
QUARTER ENDED
------------------------------------------------------------------------------ YEAR
END
(DOLLARS) 3/31 6/30 9/30 12/31 TOTAL
----------------------------------------------------------------------------------------
Dividends
1994 .04 .04 .04 .04 .16
1993 .04 .04 .04 .04 .16
Low-High
1994 23 3/8-28 3/4 22 1/2-32 1/4 25 1/4-30 7/8 22 1/2-30 3/8
1993 15 3/4-22 3/4 20 1/2-25 1/4 22 1/8-31 23-30 1/8
-----------------------------------------------------------------------------------------
ANNUAL MEETING
The Annual Meeting of Shareholders of Noble Affiliates, Inc. will be held
on Tuesday, April 25, 1995, at 10:00 a.m. at the Charles B. Goddard Center
located at "D" Street and First Avenue S.W. in Ardmore, Oklahoma. All
shareholders are cordially invited to attend.
FORM 10-K
A copy of Form 10-K, as filed with the Securities and Exchange Commission,
is available upon request by writing to Vice President - Finance and
Treasurer, Noble Affiliates, Inc., P.O. Box 1967, Ardmore, Oklahoma 73402.
Page 40
APPENDIX I
The following describes graphs which were listed in the margins of the
Management's Discussion and Analysis on pages 15 through 19 of the
Registrant's 1994 annual report.
Page 15 - Gas Reserves Added for three years
1992: 50.3 BCF's
1993: 401.4 BCF's
1994: 176.2 BCF's
Oil Reserves Added for three years
1992: 10.8 million barrels
1993: 33.3 million barrels
1994: 11.5 million barrels
Page 16 - Costs Incurred for Acquisitions, Exploration and
Development
1992: $75.5 million
1993: $515.0 million
1994: $189.7 million
Average Finding Cost Per BOE for three years
1992: $3.96
1993: $5.14
1994: $4.64
Page 17 Gas Revenues for three years
1992: $134.2 million - $1.81 Average price per mcf
1993: $159.2 million - $2.10 Average price per mcf
1994: $174.5 million - $1.97 Average price per mcf
Oil Revenues for three years
1992: $120.2 million - $18.68 Average price per barrel
1993: $111.3 million - $15.91 Average price per barrel
1994: $122.9 million - $14.90 Average price per barrel
Page 18 Net Income for three years
*1992: $41.2 million
1993: $12.6 million
1994: $3.2 million
*Includes sale of investment NGC
Average Production and Lifting Cost Per BOE for three years
1992: $3.60
1993: $3.76
1994: $3.20
Page 19 DD&A Expense Per BOE of Production for three years
1992: $5.00 per barrel
1993: $5.37 per barrel
1994: $5.46 per barrel
SG&A Expense Per Boe of Production for three years
1992: $1.64 per barrel
1993: $1.59 per barrel
1994: $1.56 per barrel