<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
---------
FORM 10-K
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal year ended DECEMBER 31, 1994
Commission file number 1-10447
CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 04-3072771
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
15375 Memorial Drive, Houston, Texas 77079
(Address of principal executive offices including Zip Code)
(713) 589-4600
(Registrant's telephone number)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -------------------
CLASS A COMMON STOCK, PAR VALUE $.10 PER SHARE NEW YORK STOCK EXCHANGE
RIGHTS TO PURCHASE PREFERRED STOCK NEW YORK STOCK EXCHANGE
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of Class A Common Stock, par value $.10 per
share ("Common Stock"), held by non-affiliates (based upon the closing sales
price on the New York Stock Exchange on March 1, 1995), was approximately
$307,434,609.
As of February 28, 1995, there were 22,772,934 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents are incorporated herein by reference in
portions of the parts of this report indicated below:
DOCUMENT INCORPORATED AS TO
Annual Report to Stockholders for the Parts I, II and IV
Registrant's Fiscal Year Ended
December 31, 1994
Proxy Statement for the 1995 Annual Meeting Parts III, Items 10, 11, 12,
of Stockholders (to be filed not later than 120 and 13
days after December 31, 1994).
<PAGE>
PART I
ITEM 1. BUSINESS
GENERAL
Cabot Oil & Gas Corporation (the "Company") explores for, develops, produces,
purchases, stores, transports, purchases and markets natural gas and, to a
lesser extent, produces and sells crude oil. Substantially all of the Company's
operations are in the Appalachian Region of West Virginia, Pennsylvania and New
York and in the Western Region, including the Anadarko Basin of southwestern
Kansas, Oklahoma and the Texas Panhandle, in the Green River Basin of Wyoming
and South Texas. At December 31, 1994, the Company had 1,001.3 Bcfe of total
proved reserves, 95% of which was natural gas. A significant portion of the
Company's natural gas reserves is located in long-lived fields with extended
production histories.
The Company, a Delaware corporation, was organized in 1989 as the successor
to the oil and gas business of Cabot Corporation ("Cabot"), which was founded in
1891. In 1990, the Company completed its initial public offering of
approximately 18% of the outstanding common stock held by Cabot. Cabot
distributed the remaining common stock of the Company to the shareholders of
Cabot in 1991. Since that time, the Company has been publicly traded on the New
York Stock Exchange. See Note 1 of the Notes to the Consolidated Financial
Statements incorporated herein by reference in Item 8 hereof for further
discussion.
Unless the context otherwise requires, all references herein to the Company
include Cabot Oil & Gas Corporation, its predecessors and subsidiaries.
Similarly, all references to Cabot include Cabot Corporation and its affiliates.
All references to wells are gross, unless otherwise stated.
The following table summarizes certain information, at December 31, 1994,
regarding the Company's proved reserves, productive wells, developed and
undeveloped acreage and infrastructure.
SUMMARY OF RESERVES, PRODUCTION, ACREAGE AND OTHER INFORMATION BY AREAS OF
OPERATION (1) (2)
<TABLE>
<CAPTION>
Total Appalachian Western
Company Region Region (3)
---------- ------------ ----------
<S> <C> <C> <C>
Reserves/Production:
-------------------
Proved reserves
Developed (Bcfe)................ 852.1 475.6 376.5
Undeveloped (Bcfe).............. 149.2 85.9 63.3
Total (Bcfe).................... 1001.3 561.5 439.8
Daily production (MMcfe) net...... 173.3 81.6 91.7
Gross productive wells............ 5,875.0 4,125.0 1,750.0
Net productive wells.............. 4,513.6 3,779.2 734.4
Percent of wells operated......... 83.9% 97.5% 50.3%
Acreage/Infrastructure:
Net acreage (thousands of acres)
Developed acreage............... 999,946 758,238 241,708
Undeveloped acreage............. 604,095 383,692 220,403
Total........................... 1,604,041 1,141,930 462,111
</TABLE>
1
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----------------
(1) As of December 31, 1994. For additional information regarding the
Company's estimates of proved reserves and other data, see "Business --
Reserves", and the Supplemental Oil and Gas Information to the Consolidated
Financial Statements.
(2) Certain numbers may not add due to rounding.
(3) Includes all properties outside the Appalachian Region, including
properties located in Anadarko, the Rocky Mountains and the Gulf Coast
areas.
EXPLORATION, DEVELOPMENT AND PRODUCTION
The Company is one of the largest producers of natural gas in the
Appalachian basin, where it has conducted operations for more than a century.
The Company has had operations in the Anadarko basin for over 50 years. The
Company acquired its operations in the Rocky Mountains and the Gulf Coast
pursuant to the merger of Washington Energy Resources Company with the Company
which was completed in May of 1994. Historically, the Company has maintained
its reserve base through low-risk development drilling and strategic
acquisitions. The Company continues to focus its operations in the Appalachian
and Western Regions through development of undeveloped reserves and acreage,
acquisition of oil and gas producing properties and, to a lesser extent,
exploration.
APPALACHIAN REGION
The Company's exploration, development and production activities in the
Appalachian Region are concentrated in Pennsylvania, West Virginia and New York.
Operations are managed by a regional office in Pittsburgh. At December 31,
1994, the Company had approximately 562 Bcfe of proved reserves (substantially
all natural gas) in the Appalachian Region, constituting 56% of the Company's
total proved reserves.
The Company has 4,125 productive wells (3,779.2 net) of which 4,022 wells
are operated by the Company. There are multiple producing intervals which
include the Medina, Berea, and Big Lime trend formations at depths primarily
ranging from 1,500 to 6,000 feet. Average net daily production in 1994 was 8l.6
MMcfe. While natural gas production volumes from Appalachian reservoirs are
relatively low on a per-well basis compared to other areas of the United States,
the productive life of Appalachian reserves is relatively long.
In 1994, the Company drilled 142 wells (135.2 net) in the Appalachian
Region, of which 140 were development wells (134.7 net). Capital and
exploration expenditures, including pipeline expenditures for the year were
approximately 49.6 million. In the 1995 drilling program year, the Company has
plans to drill 11.9 net wells.
During 1995, the Company intends to curtail development activity in
Appalachia to focus on higher potential return opportunities in the Western
Region.
At December 31, 1994, the Company had 1,141,930 million net acres in the
region, including 758,238 net developed acres.
The Company also owns and operates a brine treatment plant near Franklin,
Pennsylvania. The plant, which began operating in 1985, processes and treats
waste fluid generated during the drilling, completion and subsequent production
of oil and gas wells. The plant provides services to the Company and certain
other oil and gas producers in southwestern New York, eastern Ohio and western
Pennsylvania.
The Company believes that it gains operational efficiency in the
Appalachian Region because of its large acreage position, its high concentration
of wells, its natural gas gathering and pipeline systems and its storage
capacity.
2
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WESTERN REGION
On January 26, 1995, the Company announced that it intended to consolidate
the management of its non-Appalachian holdings (Anadarko, Rocky Mountains and
Gulf Coast) into a single Western Region. This allows the Company to reduce
regional office and administrative costs, improve operating effectiveness and
better control the capital allocation process. Operations for the Western
Region will be managed from a regional office in Denver.
The Company's exploration, development and production activities in the
Western Region are primarily focused in the Anadarko basin in Kansas, Oklahoma
and the Panhandle of Texas, in the Green River Basin of Wyoming and in South
Texas. At December 31, 1994, the Company had approximately 439.8 Bcfe of proved
reserves (89.3% natural gas) in the Western Region, constituting 44% of the
Company's total proved reserves.
Anadarko
The Company has 991 productive wells (549.2 net) in Anadarko of which 684
wells are operated by the Company. Principal producing intervals in Anadarko
are in the Chase, Chester and Morrow formations at depths ranging from 1,500 to
11,000 feet. Average net daily production in 1994 was 56.3 MMcfe.
In 1994, the Company drilled 34 wells (25.3 net) in Anadarko (32
development wells, 24.8 net). Capital and exploration expenditures for the year
were $49.6 million. In the 1995 drilling program year, the Company currently
has plans to drill 3.3 net wells.
At December 31, 1994, the Company had 207,443 net acres in Anadarko,
including approximately 181,428 net developed acres. At year end, the Company
had identified 56.4 net proved undeveloped drilling locations.
Washington Energy Resources Company Acquisition
On May 2, 1994, the Company completed the merger between a Company
subsidiary and Washington Energy Resources Company ("WERCO"), formerly a
subsidiary of Washington Energy Company. The Company acquired the stock of
WERCO in a tax-free exchange. The Company issued 2,133,000 shares of common
stock and 1,134,000 shares of 6% convertible redeemable preferred stock ($50 per
share stated value) to Washington Energy Company in exchange for the capital
stock of WERCO. In addition, the Company advanced cash to repay intercompany
indebtedness between WERCO and Washington Energy Company of $63.7 million.
Exploration, development and production activities acquired from WERCO are
located primarily in the Green River Basin in Wyoming (Rocky Mountains). At
December 31, 1994, the Rocky Mountains accounted for approximately 172 Bcfe of
proved reserves (82% natural gas), constituting 17% of the Company's total
proved reserves.
The Company has 461 productive wells (110.6 net) in the Rocky Mountains of
which 125 are operated by the Company. Principal producing formations are the
Frontier and the Dakota at depths ranging from 10,000 to 14,000 feet. Average
net daily production in 1994 was 34.1 MMcfe.
In 1994, the Company drilled 21 wells (6.8 net) in the Rocky Mountains.
Capital and exploration expenditures for the year, excluding the WERCO
acquisition cost, were approximately $8.4 million. In the 1995 drilling program
year, the Company currently has plans to drill 4.5 net wells.
At December 31, 1994, the Company had approximately 206,700 net acres in
the Rocky Mountains, including 41,136 net developed acres. At year end, the
Company had identified 13.3 net proved undeveloped drilling locations.
3
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In addition, as part of the WERCO transaction, the Company acquired certain
assets in South Texas (the Gulf Coast). The Company expects that the Gulf Coast
area will have significant growth potential in exploration and development. At
December 31, 1994 the Gulf Coast area accounted for approximately 22.6 Bcfe of
proved reserves (75 % natural gas), constituting 2% of the Company's total
proved reserves. The Company is primarily drilling in the Wilcox and Vicksburg
formations.
GAS MARKETING
The Company is engaged in a wide array of marketing activities designed to
offer its customers long-term reliable supplies of natural gas. Utilizing its
pipeline and storage facilities, gas procurement ability and transportation and
natural gas risk management expertise, the Company provides a menu of services
that includes gas supply management, short and long-term supply contracts,
capacity brokering and risk management alternatives. Sales volumes grew
substantially in 1994 as the Company increased the amount of natural gas
purchased for resale. This increase was primarily due to an increase in gas
purchased from producers and marketers in the Gulf of Mexico that was then
transported and sold using the Company's Appalachian pipeline system. Volumes
purchased and sold in this manner increased from approximately 6 Bcf in 1993 to
approximately 16 Bcf in 1994.
The marketing of natural gas has changed significantly as a result of Order
636 ("Order 636"), which was issued by the Federal Energy Regulatory Commission
in 1992. Order 636 required pipelines to unbundle their gas sales, storage and
transportation services. As a result, local distribution companies and end-
users will separately contract these services from gas marketers and producers.
Order 636 has had the effect of creating greater competition in the industry and
it has also provided the Company the opportunity to reach broader markets. In
1993 and 1994, there was both an increase in the number of third-party producers
that use the Company to market their gas. In addition, the Company has
experienced, as a result of Order 636, increased competition for markets which
has placed pressure on margins.
APPALACHIAN REGION
The Company's principal markets for its Appalachian Region natural gas are
in the northeastern United States. The Company's marketing subsidiary purchases
all of the Company's natural gas production in the Appalachian Region as well as
production from local third-party producers and other suppliers to aggregate
larger volumes of natural gas for resale. This marketing subsidiary sells
natural gas to industrial customers, local distribution companies and gas
marketers both on and off the Company's pipeline system.
A majority of the Company's natural gas sales volume in the Appalachian
Region is being sold at market responsive prices under contracts with a term of
one year or less. Of these short term sales, spot market sales are made under
month-to-month contracts while industrial and utility sales generally are made
under year-to-year contracts. Approximately 40% of the Appalachian production
is sold on fixed price contracts which typically renew annually.
The Company's Appalachian production is generally sold at a premium price
to production from other producing regions due to its close proximity to
markets. However, that premium has been reduced from historic levels due to
increased competition in the market place resulting in part from changes in
transportation and sales arrangements due to the implementation of pipeline open
access tariffs and Order 636.
The Company operates a number of gas gathering and pipeline systems, made
up of approximately 3,600 miles of pipeline with interconnects to four
interstate and five local distribution companies ("LDCs"). The Company's
natural gas gathering and pipeline systems enable the Company to connect new
wells quickly and to transport natural gas from the wellhead directly to
interstate pipelines, local distribution companies and industrial end-users.
Control of its gathering and pipeline systems also enables the Company to
purchase, transport and sell natural gas produced by third parties. In
addition, the Company can
4
<PAGE>
undertake development drilling operations without relying upon third parties to
transport its natural gas while incurring only the incremental costs of pipeline
and compressor additions to its system.
The Company has two natural gas storage fields located in West Virginia,
with a combined working capacity of approximately 4 Bcf of natural gas. The
Company uses these storage fields to take advantage of the seasonal variations
in the demand for natural gas and the higher prices typically associated with
winter natural gas sales, while maintaining production at a nearly constant rate
throughout the year. The storage fields also enable the Company to periodically
increase the volume of natural gas it can deliver by more than 35% above the
volume that it could deliver solely from its production in the Appalachian
Region. The pipeline systems and storage fields are fully integrated with the
Company's producing operations.
WESTERN REGION
The Company's principal markets for Western Region natural gas are in the
northwestern and midwestern United States. The Company's marketing subsidiaries
purchase all of the Company's natural gas production in the Western Region.
These marketing subsidiaries sell the natural gas to natural gas processors,
LDCs, industrial customers and marketing companies.
Currently, a majority of the Company's natural gas production in the
Western Region is being sold primarily under contracts with a term of one year
or less at market-responsive prices. Approximately 20% of the Western Region's
production is sold under a 14-year cogeneration contract under which the price
escalates at 5% per year. The Western Region properties are connected to the
majority of the midwestern and northwestern interstate pipelines, affording the
Company access to multiple markets.
RISK MANAGEMENT
In 1994, the Company entered into certain price swap transactions to manage
price risks associated with the purchase and sale of natural gas. The Company
utilized certain natural gas price swap agreements ("price swaps") to attempt to
manage price risk more effectively and improve the Company's realized natural
gas prices. These price swaps call for payments to (or to receive payments
from) counterparties based upon the differential between a fixed and a variable
gas price. The current price swaps run for periods of a year or less and have a
remaining notional contract amount of 5,875,000 MMbtu of natural gas at December
31, 1994. The Company plans to continue this strategy in the future.
RESERVES
CURRENT RESERVES
The Company's drilling program, combined with the WERCO Acquisition created
a 21% increase in proved reserves. The following table sets forth information
regarding the Company's estimates of its net proved reserves at December 31,
1994.
<TABLE>
<CAPTION>
Natural Gas Liquids(1) Natural Gas Equivalents(2)
----------- ---------- --------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
--------- ----------- ------- ---------- ----------- ----- --------- ----------- ---------
(MMcf) (MBbl) (MMcfe)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Appalachian 474,574 85,920 560,494 167 0 167 475,576 85,920 561,496
Western (3) 331,339 61,250 392,589 7,537 332 7,869 376,561 63,242 439,803
------- ------- ------- ----- --- ----- ------- ------- ---------
Total 805,913 147,170 953,083 7,704 332 8,036 852,137 149,162 1,001,299
======= ======= ======= ===== === ===== ======= ======= =========
--------------------
</TABLE>
(1) Liquids include crude oil, condensate and natural gas liquids (NGL).
(2) Natural Gas Equivalents are determined using the ratio of 6.0 Mcf of natural
gas to 1.0 Bbl of crude oil or condensate.
(3) Includes proved reserves attributable to Anadarko, Rocky Mountains and the
Gulf Coast areas.
5
<PAGE>
The reserve estimates presented herein were prepared by the Company's
petroleum engineering staff and audited by Miller and Lents, Ltd., independent
petroleum engineers. For additional information regarding the Company's
estimates of proved reserves, the review of such estimates by Miller and Lents,
Ltd. and certain other information regarding the Company's oil and gas reserves,
see the Supplemental Oil and Gas Information to the Consolidated Financial
Statements incorporated herein by reference in Item 8 hereof. A copy of the
letter by Miller and Lents, Ltd., has been filed as an exhibit to this Form 10-
K. The Company's estimates of reserves set forth in the foregoing table do not
differ materially from those filed by the Company with other federal agencies.
The Company's reserves are sensitive to natural gas sales prices and their
effect on economic producing rates. The Company's reserves are based on oil and
gas prices in effect at December 31, 1994.
There are numerous uncertainties inherent in estimating quantities of proved
reserves, including many factors beyond the control of the Company, and,
therefore, the reserve information set forth in this Form 10-K is estimated.
Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
As a result, estimates of different engineers often vary. In addition, results
of drilling, testing and production subsequent to the date of an estimate may
justify revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of crude oil and natural gas that are ultimately
recovered. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based. In general, the volume
of production from oil and gas properties owned by the Company declines as
reserves are depleted. Except to the extent the Company acquires additional
properties containing proved reserves or conducts successful exploration and
development activities or both, the proved reserves of the Company will decline
as reserves are produced.
6
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HISTORICAL RESERVES
The following table sets forth certain information regarding the Company's
estimated proved reserves for the periods indicated.
<TABLE>
<CAPTION>
Oil, Condensate
Natural Gas & NGLs Total
(MMcf) (MBbl) (MMcfe)
APP WEST TOTAL APP WEST TOTAL APP WEST TOTAL
-------- -------- -------- ---- ------ ------ -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
December 31, 1991............... 496,109 220,341 716,450 78 1,135 1,213 496,577 227,151 723,728
Revisions of prior estimates.... (1,901) (7,046) (8,947) 44 191 235 (1,637) (5,900) (7,537)
Extensions, discoveries,
other additions................. 33,262 23,613 56,875 6 505 511 33,298 26,643 59,941
Production...................... (25,614) (19,852) (45,466) (14) (148) (162) (25,698) (20,740) (46,438)
Purchases of reserves in place.. 3,425 2,346 5,771 2 1 3 3,437 2,352 5,789
Sales of reserves in place...... (17) 0 (17) 0 (1) (1) (17) (6) (23)
------- ------- ------- --- ----- ----- ------- ------- ---------
December 31, 1992............... 505,264 219,402 724,666 116 1,683 1,799 505,960 229,500 735,460
Revisions of prior estimates.... (17,621) (649) (18,270) (6) (349) (355) (17,657) (2,743) (20,400)
Extensions, discoveries,
other additions................. 35,439 22,826 58,265 1 436 437 35,445 25,442 60,887
Production...................... (26,191) (19,859) (46,050) (13) (332) (345) (26,269) (21,851) (48,120)
Purchases of reserves in place.. 60,508 32,623 93,131 38 1,293 1,331 60,736 40,381 101,117
Sales of reserves in place...... (1,466) (1,996) (3,462) 0 (41) (41) (1,466) (2,242) (3,708)
------- ------- ------- --- ----- ----- ------- ------- ---------
December 31, 1993............... 555,933 252,347 808,280 136 2,690 2,826 556,749 268,487 825,236
Revisions of prior estimates.... (9,088) (15,539) (24,627) 54 (152) (98) (8,764) (16,451) (25,215)
Extensions, discoveries,
other additions................. 32,391 32,438 64,829 0 181 181 32,391 33,524 65,915
Production...................... (29,668) (28,651) (58,319) (21) (803) (824) (29,794) (33,469) (63,263)
Purchases of reserves in place.. 16,963 151,994 168,957 0 5,992 5,992 16,963 187,946 204,909
Sales of reserves in place...... (6,037) 0 (6,037) (2) (39) (41) (6049) (234) (6,283)
------- ------- ------- --- ----- ----- ------- ------- ---------
December 31, 1994............... 560,494 392,589 953,083 167 7,869 8,036 561,496 439,803 1,001,299
======= ======= ======= === ===== ===== ======= ======= =========
Proved Developed Reserves:
December 31, 1991............... 385,629 185,036 570,665 78 1,126 1,204 386,097 191,792 577,889
December 31, 1992............... 398,895 184,778 583,673 116 1,394 1,510 399,591 193,142 592,733
December 31, 1993............... 458,682 210,990 669,672 136 2,210 2,346 459,498 224,250 683,748
December 31, 1994............... 474,574 331,339 805,913 167 7,537 7,704 475,576 376,561 852,137
----------------
</TABLE>
(1) For the years ended December 31, 1991, 1992 and 1993 the Western reserves
are attributable to Anadarko only.
Note: Natural gas equivalents are determined using the ratio of 6.0 Mcf of
natural gas to 1.0 Bbl of crude oil or condensate.
APP = Appalachian Region
WEST = Western Region (1)
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VOLUMES AND PRICES; PRODUCTION COSTS
The following table sets forth historical information regarding the Company's
sales and production volumes and average sales prices received for, and average
production costs associated with, its sales of natural gas and crude oil,
condensate and natural gas liquids (NGL) for the periods indicated.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1994 1993 1992
------ ------ ------
(in millions)
<S> <C> <C> <C>
Net Wellhead Sales Volume:
Natural Gas (Bcf) (1)
Appalachian Region...................... 28.7 23.1 24.0
Western Region (2)...................... 28.3 19.8 19.9
Crude/Condensate/NGL's (MBbl)
Appalachian Region...................... 20 13 14
Western Region.......................... 804 332 148
Purchased Gas
Volumes (Bcf)........................... 48.3 21.6 20.6
Purchase Cost ($/Mcf)................... $ 1.92 $ 2.09 $ 1.90
Natural Gas Sales Price ($/Mcf)(3)
Appalachian Region...................... $ 2.47 $ 2.69 $ 2.50
Western Region.......................... $ 1.73 $ 1.94 $ 1.62
Weighted Average......................... $ 2.14 $ 2.40 $ 2.18
Crude/Condensate Sales Price ($/BbL)(3).. $16.66 $16.58 $19.03
Production Costs ($/Mcfe)(4)............. $ 0.62 $ 0.65 $ 0.57
----------------
</TABLE>
(1) Equal to the aggregate of production and the net changes in storage and
exchanges.
(2) Includes information regarding Anadarko, Rocky Mountains and Gulf Coast for
the year ended December 31, 1994; includes Anadarko only for the years ended
December 31, 1992 and 1993.
(3) Represents the average sales prices for all volumes (including royalty
volumes) sold by the Company during the periods shown.
(4) Production costs include direct lifting costs (labor, repairs, maintenance,
materials and supplies) and the costs of administration of production
offices, insurance and property and severance taxes but is exclusive of
depreciation and depletion applicable to capitalized lease acquisition,
exploration and development expenditures.
ACREAGE
The following tables summarize the Company's gross and net developed and
undeveloped leasehold and mineral acreage at December 31, 1994. Acreage in
which the Company's interest is limited to royalty and overriding royalty
interests is excluded. The undeveloped mineral fee acreage in West Virginia is
unleased.
8
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Leasehold Average
<TABLE>
<CAPTION>
At December 31, 1994
--------------------
Developed Undeveloped Total
--------- ----------- -----
Gross Net Gross Net Gross Net
--------- ------- ------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
State:
Alabama.................. -- -- 11,427 11,284 11,427 11,284
Arkansas................. -- -- 240 6 240 6
California............... 290 11 -- -- 290 11
Colorado................. 16,425 14,893 61,367 51,294 77,792 66,187
Indiana.................. -- -- 17,437 17,437 17,437 17,437
Kansas................... 32,304 28,965 33,246 11,207 65,550 40,172
Kentucky................. 2,680 983 128 128 2,808 1,111
Louisiana................ 1,584 182 3,892 727 5,476 909
Maryland................. -- -- 7 7 7 7
Montana.................. 554 262 840 443 1,394 705
New Mexico............... 720 20 -- -- 720 20
New York................. 22,387 16,917 24,331 23,576 46,718 40,493
North Dakota............. 7,039 522 1,630 138 8,669 660
Ohio..................... 42 21 36,380 16,966 36,422 16,987
Oklahoma................. 165,230 104,076 20,044 14,460 185,274 118,536
Pennsylvania............. 165,874 154,193 123,401 112,546 289,275 266,739
Texas.................... 78,740 52,658 6,788 4,323 85,528 56,981
Utah..................... 2,659 933 31,308 24,729 33,967 25,662
Virginia................. 3,748 3,095 15,737 15,737 19,485 18,832
West Virginia............ 553,580 519,198 153,203 138,774 706,783 657,972
Wyoming.................. 50,902 24,314 141,115 86,155 192,017 110,469
--------- ------- ------- ------- --------- ---------
Total 1,104,758 921,243 682,521 529,937 1,787,279 1,451,180
========= ======= ======= ======= ========= =========
Offshore:
Louisiana................ -- -- 20,000 12,500 20,000 12,500
--------- ------- ------- ------- --------- ---------
Total -- -- 20,000 12,500 20,000 12,500
========= ======= ======= ======= ========= =========
Canada:
Alberta.................. 396 90 4,512 2,147 4,908 2,237
British Columbia......... 479 111 2,573 643 3,052 754
--------- ------- ------- ------- --------- ---------
Total 875 201 7,085 2,790 7,960 2,991
========= ======= ======= ======= ========= =========
</TABLE>
Mineral Fee Acreage
<TABLE>
<CAPTION>
At December 31, 1994
--------------------
Developed Undeveloped Total
--------- ----------- -----
Gross Net Gross Net Gross Net
--------- ------- ------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
State:
Colorado................. -- -- 265 21 265 21
Kansas................... 160 128 -- -- 160 128
New York................. -- -- 6,545 1,636 6,545 1,636
Oklahoma................. 16,093 14,011 -- -- 16,093 14,011
Pennsylvania............. 94 94 1,588 517 1,682 611
Texas.................... 750 532 652 326 1,402 858
West Virginia............ 76,496 63,737 57,910 56,368 134,406 120,105
--------- ------- ------- ------- --------- ---------
Total................... 93,593 78,502 66,960 58,868 160,553 137,370
========= ======= ======= ======= ========= =========
Aggregate Total........... 1,199,226 999,946 776,566 604,095 1,975,792 1,604,041
========= ======= ======= ======= ========= =========
</TABLE>
9
<PAGE>
TOTAL NET ACREAGE BY AREA OF OPERATION
<TABLE>
<CAPTION>
At December 31, 1994
--------------------
Developed Undeveloped Total
--------- ----------- ---------
<S> <C> <C> <C>
Appalachian Region.. 758,238 383,692 1,141,930
Western Region...... 241,708 220,403 462,111
------- ------- ---------
Total.......... 999,946 604,095 1,604,041
======= ======= =========
</TABLE>
PRODUCTIVE WELL SUMMARY (1)
The following table reflects the Company's ownership at December 31, 1994 in
natural gas and oil wells in the Appalachian Region (consisting of various
fields located in West Virginia, Pennsylvania, New York, Ohio, Virginia and
Kentucky), and in the Western Region (consisting of various fields located in
Louisiana, Oklahoma, Texas, Kansas, North Dakota, Utah, Colorado, Wyoming and
Canada).
<TABLE>
<CAPTION>
Natural Gas Oil Total
----------- --- -----
Gross Net Gross Net Gross Net
----- ------- ----- ----- ----- -------
<S> <C> <C> <C> <C> <C> <C>
Appalachian Region.. 4,108 3,764.6 17 14.6 4,125 3,779.2
Western Region...... 1,119 545.0 631 189.4 1,750 734.4
----- ------- --- ----- ----- -------
Total............ 5,227 4,309.6 648 204.0 5,875 4,513.6
===== ======= === ===== ===== =======
----------------
</TABLE>
(1) "Productive" wells are producing wells and wells capable of production.
DRILLING ACTIVITY
The Company drilled, participated in the drilling of, or acquired wells as set
forth in the table below for the periods indicated:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1994 1993 1992
---- ---- ----
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Appalachian Region:
Development Wells
Natural Gas....... 133 128.2 117 114.5 69 62.7
Dry............... 7 6.5 5 5.0 3 2.5
Exploratory Wells
Natural Gas....... 0 0.0 1 0.3 0 0.0
Dry............... 2 0.5 3 2.3 1 1.0
---- ----- ---- ----- -- ----
Total........... 142 135.2 126 122.1 73 66.2
==== ===== ==== ===== == ====
Wells Acquired (1)
Natural Gas....... 9 21.1 396 397.8 8 36.2
Oil............... 0 0.0 6 6.0 0 0.0
---- ----- ---- ----- -- ----
Total........... 9 21.1 402 403.8 8 36.2
==== ===== ==== ===== == ====
Wells in Progress
at End of Period.. 2 1.3 0 0.0 1 1.0
</TABLE>
10
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1994 1993 1992
---- ---- ----
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Western Region (2):
Development Wells
Natural Gas....... 48 24.7 26 19.2 23 19.3
Oil............... 7 3.1 5 3.6 4 4.0
Dry............... 8 5.3 5 4.9 4 2.7
Exploratory Wells
Natural Gas....... 0 0 0 0.0 1 0.5
Dry............... 3 0.8 0 0.0 3 2.1
---- ----- ---- ----- -- ----
Total........... 66 33.9 36 27.7 35 28.6
==== ===== ==== ===== == ====
Wells Acquired (1)
Natural Gas....... 413 115.7 218 106.5 2 3.7
Oil............... 140 52.3 303 63.6 0 0.0
---- ----- ---- ----- -- ----
Total........... 553 168.0 521 170.1 2 3.7
==== ===== ==== ===== == ====
Wells in Progress
at End of Period.. 7 1.9 3 3.0 0 0.0
----------------
</TABLE>
(1) Includes the acquisition of net interest in certain wells in the Appalachian
Region and in the Western Region in 1994, 1993 and 1992 in which the Company
already held an ownership interest.
(2) The years ended December 31, 1992 and 1993 included information for Anadarko
only.
COMPETITION
The Company has experienced significant competition in its primary producing
areas. The Company actively competes against some companies with substantially
larger financial and other resources, particularly in the Western Region. The
Company believes that its competitive position is affected by price, contract
terms and quality of service, including pipeline connection times, distribution
efficiencies and reliable delivery record. The Company believes that its
extensive acreage position and existing natural gas gathering and pipeline
systems and storage fields give it a competitive advantage over certain other
producers in the Appalachian Region which do not have such systems or facilities
in place. The Company also believes that its competitive position in the
Appalachian Region is enhanced by the absence of significant competition from
major oil and gas companies.
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
The Company had no sales to any customer that exceeded 10% of the Company's
total revenues in 1994.
SEASONALITY
Demand for natural gas has historically been seasonal in nature, with peak
demand and typically higher prices occurring during the colder winter months.
11
<PAGE>
REGULATION OF OIL AND NATURAL GAS PRODUCTION
The Company's oil and gas production and transportation operations are subject
to various types of regulation, including regulation by state and federal
agencies. Although such regulations have an impact on the Company and others in
the oil, gas and pipeline industry, the Company does not believe that it is
affected in a significantly different manner by these regulations than others in
the oil and gas industry.
Legislation affecting the oil and gas industry is under constant review for
amendment or expansion. Numerous departments and agencies, both federal and
state, are authorized by statute to issue, and have issued, rules and
regulations binding on the oil and gas industry and its individual members. The
failure to comply with such rules and regulations can result in substantial
penalties. Many states require permits for drilling operations, drilling bonds
and reports concerning operations. Many states also have statutes or
regulations addressing conservation matters, including provisions for the
utilization or pooling of oil and gas properties, the establishment of maximum
rates of production from oil and gas wells and the regulation of spacing,
plugging and abandonment of such wells.
With respect to the establishment of maximum production rates from natural gas
wells, certain producing states, in an attempt to limit production to market
demand, have recently adopted (Texas and Oklahoma) or are considering adopting
(Louisiana) measures that alter the methods previously used to prorate gas
production from wells located in these states. For example, the new Texas rules
provide for reliance on information filed monthly by well operators, in addition
to historical production data for the well during comparable past periods, to
arrive at an allowable. This is in contrast to historic reliance on forecasts
of upcoming takes filed monthly by purchasers of natural gas in formulating
allowables, a procedure which resulted in substantial excess allowables over
volumes actually produced. The Company cannot predict whether other states will
adopt similar or other procedures for prorating gas production.
While it is still unclear how these new regulations will be administered, the
effect of these regulations could be to decrease allowable production on the
Company's properties and thereby decrease revenues. However, management
believes that such regulation would not have a significant impact on the
Company's revenues. By decreasing the amount of natural gas available in the
market, such regulations could also have the effect of increasing prices of
natural gas, although there can be no assurance that any such increase will
occur. The company cannot predict whether these new regulations for rationing
gas production will be challenged in the courts or what the outcome of such
challenges would be.
The Natural Gas Act of 1938 (the "NGA") regulates the interstate
transportation and certain sales for resale of natural gas. The Natural Gas
Policy Act of 1978 (the "NGPA") regulates the maximum selling prices of certain
categories of natural gas, when sold in so-called "first sales" in interstate or
intrastate commerce, and provides for phased deregulation of price controls of
the first sales of several categories of natural gas. These statutes were
administered by the Federal Energy Regulatory Commission ("FERC"). As a result
of the enactment of the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol
Act") on July 26, 1989, all remaining "first sales" price regulations imposed by
the NGA and NGPA terminated on January 1, 1993.
Commencing in late 1985 and early 1986, the FERC issued a series of orders
which significantly altered the marketing and pricing of natural gas. Among
other things, the new regulations require interstate pipelines that elect to
transport natural gas for others under self-implementing authority to provide
transportation services to all shippers (e.g., producers, marketers, local
distributors and end-users) on an open and non-discriminatory basis, and permit
each existing firm sales customer of such pipelines to modify, over at least a
five-year period, its existing firm purchase obligations.
12
<PAGE>
Order No. 500 was issued by the FERC on August 7, 1989, in response to the
remand of Order No. 436 by the United States Court of Appeals for the District
of Columbia. Order No. 500 repromulgated most of the provisions of Order No.
436 but added certain other provisions primarily intended to address take-or-pay
contract claims.
In April 1992, the FERC issued Order 636, a complex regulation which is
expected to have a major impact on natural gas pipeline operations, services and
rates. Among other things, Order 636 requires each interstate pipeline company
to "unbundle" its traditional wholesale services and create and make available
on an open and nondiscriminatory basis numerous constituent services (such as
gathering services, storage services, firm and interruptible transportation
services, and stand-by sales services) and to adopt a new rate-making
methodology to determine appropriate rates for those services. To the extent
the pipeline company or its sales affiliate makes gas sales as a merchant in the
future, it will do so in direct competition with all other sellers pursuant to
private contracts; however, under Order 636 pipeline companies are not required
to remain "merchants" of gas, and many of the interstate pipeline companies have
or will become "transporters" only. On August 3, 1992, the FERC issued Order
636-A, which largely reaffirmed Order 636 and denied a stay of the
implementation of the new rules pending judicial review. On November 27, 1992,
the FERC issued Order 636-B which uniformly upheld the requirements and
regulations adopted in Order 636 and Order 636-A. As a result of these events,
individual so-called "restructuring" proceedings are ongoing before the FERC
whereby each interstate pipeline company will develop and propose particularized
features and procedures for its system to implement Order 636 requirements.
These new rules are already the subject of several appeals in the United States
Courts of Appeals and to additional action by the FERC. The Company cannot
predict whether Order 636 will be affirmed on appeal. However, "open access"
transportation under Order 636 has provided the Company with the opportunity to
sell gas to a wide variety of markets.
The Company's pipeline systems and storage fields are regulated for safety
compliance by the Department of Transportation, the West Virginia Public Service
Commission, the Pennsylvania Department of Natural Resources and the New York
Department of Public Service. The Company's pipeline systems in each state
operate independently and are not interconnected.
ENVIRONMENTAL REGULATIONS
The Company's operations are subject to extensive federal, state and local
laws and regulations relating to the generation, storage, handling, emission,
transportation and discharge of materials into the environment. Permits are
required for the operation of various facilities of the Company, and these
permits are subject to revocation, modification and renewal by issuing
authorities. Governmental authorities have the power to enforce compliance with
their regulations, and violations are subject to fines, injunctions or both. It
is possible that increasingly strict requirements will be imposed by
environmental laws and enforcement policies thereunder. The Company is also
subject to the Federal Clean Air Act and the Federal Clean Air Act Amendment of
1990, which added significantly to the existing requirements established by the
Federal Clean Air Act. It is not anticipated that the Company will be required
in the near future to expend material amounts in relation to its total capital
expenditures program by reason of environmental laws and regulations. Because
such laws and regulations are frequently changed however, the Company is unable
to predict the ultimate cost of such compliance.
The Company owns and operates a brine treatment plant in Pennsylvania which
processes fluids generated by drilling and production operations. See "Business
-- Exploration, Development and Production -- Appalachian Region". The plant's
operations are regulated by Pennsylvania's Department of Environmental
Regulation.
13
<PAGE>
EMPLOYEES
The Company had approximately 495 active employees as of December 31, 1994.
The Company believes that its relations with its employees are satisfactory.
The Company has not entered into any collective bargaining agreements with its
employees.
OTHER
The Company's profitability depends on certain factors that are beyond its
control, such as natural gas and crude oil prices. The nature of the oil and
gas business involves a variety of risks, including the risk of experiencing
certain operating hazards such as fires, explosions, blowouts, cratering, oil
spills and encountering formations with abnormal pressures, the occurrence of
any of which could result in substantial losses to the Company. The operation
of the Company's natural gas gathering and pipeline systems also involves
certain risks, including the risk of explosions and environmental hazards caused
by pipeline leaks and ruptures. The proximity of pipelines to populated areas,
including residential areas, commercial business centers and industrial sites,
could exacerbate such risks. At December 31, 1994, the Company owned or
operated approximately 3,600 miles of natural gas gathering and pipeline
systems. The Company has identified certain segments of its pipelines which it
believes require repair, replacement or additional maintenance. For additional
information regarding such segments, see "Business -- Gas Marketing --
Appalachian Region." In accordance with customary industry practices, the
Company maintains insurance against some, but not all, of such risks.
ITEM 2. PROPERTIES
See "Item 1. Business".
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are defendants or parties in numerous
lawsuits or other governmental proceedings arising in the ordinary course of
business. See Note 10 of the Notes to the Consolidated Financial Statements
incorporated herein by reference in Item 8 hereof for a discussion of Company
contingencies.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
period from October 1, 1994 to December 31, 1994.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company has furnished to the Securities and Exchange Commission pursuant
to Rule 14a-3(c) an annual report to security holders for the year ended
December 31, 1994 (the "Annual Report"), that contains the information required
by Rule 14a-3. The information required by this item appears under the caption
"Price Range of Common Stock and Dividends" on page 41 of the Annual Report,
which is incorporated herein by reference and in Note 12 of the Notes to the
Consolidated Financial Statements incorporated herein by reference to Item 8
hereof.
14
<PAGE>
ITEM 6. SELECTED HISTORICAL FINANCIAL DATA
The information required by this item appears under the caption "Selected
Historical Financial Data" on page 16 of the Annual Report and is incorporated
herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND
RESULTS OF OPERATIONS.
The information required by this item appears under the caption "Financial
Review" on pages 17 through 23 of the Annual Report and is incorporated herein
by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this item appears on pages 24 through 41 of the
Annual Report and is incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information to be set forth under the caption "1. Election of Directors"
in the Company's definitive proxy statement ("Proxy Statement") in connection
with the 1995 annual stockholders meeting, is incorporated herein by reference.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about the executive officers of
the Company as of March 1, 1995, as such term is defined in Rule 3b-7
promulgated under the Securities Exchange Act of 1934.
<TABLE>
<CAPTION>
NAME AGE POSITION OFFICER SINCE
------------------------ --- -------------------------------------- -------------
<S> <C> <C> <C>
John H. Lollar 56 Chairman of the Board, Chief Executive 1992
Officer and President
Jim L. Batt 59 Vice President, Land 1988
Curtis P. Cook 52 Vice President and Regional Manager 1987
Kirk O. Kuwitzky (1) 41 Vice President, Marketing 1994
Richard T. Parrish 48 Vice President, Engineering 1993
Gerald F. Reiger 42 Vice President and Regional Manager 1995
James M. Trimble 46 Vice President, Business Development 1987
H. Baird Whitehead 44 Vice President and Regional Manager 1987
Frank A. Pici 39 Controller 1994
---------------
</TABLE>
(1) Mr. Kuwitzky's employment with the Company was terminated effective March
9, 1995 due to a Company-wide reduction in force program.
15
<PAGE>
With the exception of the following, all executive officers of the Company
have been employed by the Company and Cabot Corporation prior to the initial
public offering in 1990.
John H. Lollar joined the Company in October 1992 being elected President and
Director. In January 1993, Mr. Lollar was elected Chairman of the Board and
Chief Executive Officer. Prior to joining the Company, Mr. Lollar was President
and Chief Operating Officer of Transco Exploration and Production Company from
1982 to 1992 and Executive Vice President and Chief Operating Officer, in
addition to holding other positions, of Gulf Resources & Chemical Corporation
from 1968 to 1982.
Richard T. Parrish joined the Company in August 1993 as Vice President,
Engineering. Prior to joining the Company, Mr. Parrish was Vice President,
Engineering and Planning, for Transco Exploration and Production Company from
1977 to 1992 and Assistant District Engineer, Reservoir and Production for
Texaco, Inc. from 1974 to 1977. Prior thereto, Mr. Parrish was employed in
various engineering capacities with Texaco, Inc. from 1969 to 1974.
Kirk O. Kuwitzky joined the Company in January 1994 as Vice President,
Marketing, Prior to joining the Company, he was employed by Enron Corp. from
1981-1993, most recently as Vice President - Marketing for Enron Gas Marketing.
In addition, he held various marketing positions with Enron Gas Marketing and
several positions in Enron Corporation's law department. From 1978 until 1981,
he was an attorney with Minnesota Power.
Gerald F. Reiger joined the Company in May 1994 as Regional Manager, Rocky
Mountains. Prior to joining COG, Mr. Reiger managed the Rocky Mountain Region
for Washington Energy Resources Company from 1992 to 1994. Previously he was
U.S. Operations Manager for DEKALB Energy Company from 1979 to 1992.
ITEM 11. EXECUTIVE COMPENSATION.
The information appearing under the caption "11. Executive Compensation" in
the Proxy Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information appearing under the caption "1. Election of Directors" in the
Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
16
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS AND REPORTS ON FORM 8-K.
<TABLE>
<CAPTION>
A. Index
Page Reference to
-------------------
1994
Annual
Report
------
<S> <C>
1. CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Accountants 24
Consolidated Statement of Operations 25
Consolidated Balance Sheet 26
Consolidated Statement of Cash Flows 27
Consolidated Statement of Stockholders' Equity 28
Notes to Consolidated Financial Statements 29
Supplemental Oil and Gas Information 38
Quarterly Financial Information (Unaudited) 41
</TABLE>
2. EXHIBITS
The following instruments are included as exhibits to this report. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, copies of the instrument have been included herewith.
<TABLE>
<CAPTION>
Exhibit
Number Description
----------- -------------------------------------------------------------------------------------
<S> <C>
3.1 - Certificate of Incorporation of the Company (Registration Statement No. 33-32553).
3.2 - Amended and Restated Bylaws of the Company (Registration Statement No. 33-32553).
4.1 - Form of Certificate of Common Stock of the Company (Registration Statement
No. 33-32553).
4.2 - Certificate of Designation for Series A Junior Participating Preferred Stock (included in
Exhibit 4.3).
4.3 - Rights Agreement dated as of March 28, 1991 between the Company and
The First National Bank of Boston, as Rights Agent, which includes as
Exhibit A the form of Certificate of Designation of Series A Junior
Participating Preferred Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to the Rights Agreement dated February 24, 1994.
(Included in Exhibit 10.13).
4.4 - Certificate of Designation for $3.125 Convertible Preferred Stock (Form 10-K for 1993).
</TABLE>
17
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
----------- -------------------------------------------------------------------------------------
<S> <C>
4.5 - Amended and Restated Credit Agreement dated as of December 10, 1990 among the
Company, Morgan Guaranty Trust Company, as agent and the banks named therein
(Registration Statement No. 33-37455).
(a) Amendment No. 1 to Credit Agreement dated February 1, 1992 (Form
10-K for 1991).
(b) Amendment No. 2 to Credit Agreement dated May 28, 1992 (Form 10-
K for 1993).
(c) Amendment No. 3 to Credit Agreement dated June 1, 1993 (Form 10-
K for 1993).
(d) Amendment No. 4 to Credit Agreement dated October 29, 1993 (Form
10-K for 1993).
4.6 - Note Purchase Agreement dated May 11, 1990 among the Company and certain
insurance companies parties thereto (Form 10-Q for the quarter ended June 30,
1990).
(a) First Amendment dated June 28, 1991.
(b) Second Amendment dated July 6, 1994.
4.7 - Certificate of Designation for 6% Convertible Redeemable Preferred Stock. (Included
in Exhibit 10.13).
10.1 - Agreement dated October 1, 1981 between Cabot Oil & Gas
Corporation of Delaware and Cabot Corporation, relating to the supply
of certain quantities of gas to Cabot Corporation free of the costs of
production (Registration Statement No. 33-32553).
10.2 - Gas Sales Agreement dated December 2, 1986 between Cabot Oil & Gas
Corporation of West Virginia and Cabot Corporation, granting Cabot
Corporation the right to purchase one-third of the gas produced by
certain wells (Registration Statement No. 33-32553).
10.3 - Letter Agreement dated January 11, 1990 between Morgan Guaranty Trust Company
of New York and the Company. (Registration Statement No. 33-32553).
10.4 - Form of Annual Target Cash Incentive Plan of the Company (Registration Statement
No. 33-32553).
10.5 - Form of Incentive Stock Option Plan of the Company (Registration Statement No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan (Post-
Effective Amendment No. 1 to S-8 dated April 26, 1993).
10.6 - Form of Stock Subscription Agreement between the Company and certain executive
officers and directors of the Company (Registration Statement No. 33-32553).
10.7 - Transaction Agreement between Cabot Corporation and the Company dated February 1,
1991 (Registration Statement No. 33-37455).
10.8 - Tax Sharing Agreement between Cabot Corporation and the Company dated February
1, 1991 (Registration Statement No. 33-37455).
10.9 - Amendment Agreement (amending the Transaction Agreement and the Tax Sharing
Agreement) dated March 25, 1991. (incorp. by ref. from Cabot Corporation's
Schedule 13E-4, Am. No. 6, File No. 5-30636).
</TABLE>
18
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
----------- -------------------------------------------------------------------------------------
<S> <C>
10.10 - Savings Investment Plan & Trust Agreement of the Company (Form 10-K for 1991).
(a) First Amendment to the Savings Investment Plan & Trust Agreement
dated May 21, 1993 (Form S-8 dated November 1, 1993).
(b) Second Amendment to the Savings Investment Plan & Trust Agreement
dated May 21, 1993 (Form S-8 dated November 1, 1993).
10.11 - Supplemental Executive Retirement Agreements of the Company (Form 10-K for
1991).
10.12 - Settlement Agreement and Mutual Release (Tax Issues) between Cabot Corporation
and the Company dated July 7, 1992 (Form 10-Q for the quarter ended June 30,
1992).
10.13 - Agreement of Merger dated February 25, 1994 among Washington Energy Company,
Washington Energy Resources Company, the Company and COG Acquisition
Company (Form 10-K for 1993).
10.14 - 1990 Nonemployee Director Stock Option Plan of the Company (Form S-8 dated June
23, 1990).
(a) First Amendment to 1990 Nonemployee Director Stock Option Plan
(Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
10.15 - 1994 Long-Term Incentive Plan of the Company (Form S-8 dated May 20, 1994 -
Registration Statement No. 33-53723).
10.16 - 1994 Nonemployee Director Stock Option Plan (Form S-8 dated May 20, 1994 -
Registration Statement No. 33-53723).
13 - Annual Report to stockholders for its fiscal year ending December 31, 1994 is
included as an exhibit to this report for the information of the Securities and Exchange
Commission and except for those portions thereof specifically incorporated by
reference elsewhere herein, such Annual Report should not be deemed filed as part
of this report.
21.1 - Subsidiaries of Cabot Oil & Gas Corporation.
23.1 - Consent of Coopers & Lybrand L.L.P.
23.2 - Consent of Miller and Lents, Ltd.
27 - Financial Data Schedule
99 - Miller and Lents, Ltd. Review Letter dated February 10, 1995.
</TABLE>
B. REPORTS ON FORM 8-K
None
19
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Houston, State of Texas,
on the 8th day of March 1995.
CABOT OIL & GAS CORPORATION
By: /s/ John H. Lollar
--------------------------
John H. Lollar
Chairman of the Board and Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
----------------------------------- ---------------------------------- -------------
<S> <C> <C>
/s/ John H. Lollar Chairman of the Board and March 8, 1995
----------------------------------- Chief Executive Officer (Principal
John H. Lollar Executive and Financial Officer)
/s/ Frank A. Pici Controller (Principal Accounting March 8, 1995
----------------------------------- Officer)
Frank A. Pici
/s/ Robert F. Bailey Director March 8, 1995
-----------------------------------
Robert F. Bailey
/s/ Samuel W. Bodman Director March 8, 1995
-----------------------------------
Samuel W. Bodman
/s/ Henry O. Boswell Director March 8, 1995
-----------------------------------
Henry O. Boswell
/s/ John G. L. Cabot Director March 8, 1995
-----------------------------------
John G. L. Cabot
/s/ William R. Esler Director March 8, 1995
-----------------------------------
William R. Esler
/s/ William H. Knoell Director March 8, 1995
-----------------------------------
William H. Knoell
/s/ Carl M. Mueller Director March 8, 1995
-----------------------------------
Carl M. Mueller
/s/ C. Wayne Nance Director March 8, 1995
-----------------------------------
Wayne Nance
/s/ Charles P. Siess, Jr. March 8, 1995
-----------------------------------
Charles P. Siess, Jr. Director
/s/ William P. Vititoe Director March 8, 1995
-----------------------------------
William P. Vititoe
</TABLE>
20
<PAGE>
Exhibit 4.6 (a)
FIRST AMENDMENT TO NOTE
PURCHASE AGREEMENT
First Amendment (First Amendment) to Note Purchase Agreement (the Note
Purchase Agreement) dated as of June 28, 1991 among CABOT OIL & GAS CORPORATION,
a Delaware corporation (the Issuer) and the PURCHASERS listed on the signature
pages hereof (the Purchasers).
WHEREAS, the end of the fiscal year of the Issuer has been changed from
September 30th to December 31st of each such fiscal year, and the Issuer has
requested and the Purchasers have agreed to amend the Note Purchase Agreement to
the extent necessary to reflect such change;
NOW, THEREFORE, in consideration of the foregoing and for other good and
valuable consideration, the Issuer and the Purchasers hereby agree as follows:
ARTICLE I
DEFINITIONS
SECTION 1.01. Defined Terms. Capitalized terms used herein and not
otherwise defined herein shall have the meaning ascribed to such terms in the
Note Purchase Agreement.
ARTICLE II
Amendments
SECTION 2.01. Amendment to Section 5.08. Section 5.08 of the Note
Purchase Agreement is hereby amended in its entirety to read as follows:
SECTION 5.08. Engineering Reports.
(a) On or before each of July 1, 1991 and October 1, 1991, and
thereafter by April 1 and October 1 of each subsequent year, the Issuer
shall furnish to each of the Holders a report substantially in the form of
the reserve summary included in the Confidential Memorandum (but showing in
addition information with respect to reserves in the Appalachian Basin) or
otherwise in form and substance reasonably satisfactory to the Required
Lenders which may be prepared by or under the supervision of a petroleum
engineer who may be an employee of the Issuer, which shall evaluate all net
Proved Reserves owned by the Issuer and its Subsidiaries as of the
preceding December 31 or June 30,
<PAGE>
respectively (provided, that each such report evaluating such Proved
Reserves as of the preceding June 30 of each year shall be based upon the
geologic and well data set forth in the immediately preceding Reserve
Report and shall be adjusted for the Present Value of Proved Reserves sold,
acquired or developed since the immediately preceding Reserve Report), and
which shall set forth the information necessary to determine the Present
Value of Proved Reserves as of such date.
(b) Together with the Reserve Report furnished pursuant to subsection
(a) evaluating reserves as of December 31 of any year, the Issuer shall
furnish to each of the Holders a review report thereon in form and
substance reasonably satisfactory to the Required Lender by Miller & Lents,
Ltd. Or other independent petroleum engineers of naturally recognized
standing.
SECTION 2.02. Amendment to Section 5.12. Section 5.12 of the Note
Purchase Agreement is hereby amended in its entirety to read as follows:
SECTION 5.12. Annual Coverage Ratio. (a) The Annual Coverage Ratio for
each of the fiscal years referred to in paragraph (b) of this Section 5.12,
calculated as of each December 31 and June 30 from the Reserve Report
referred to in paragraph (b) below, shall not be less than 1.2:1, provided
that no Default will arise under this Section 5.12 for a period of 60 days
after the delivery of the related Reserve Report, during which time the
Issuer or any Subsidiary may reschedule maturities of Debt, reduce Debt or
acquire additional Petroleum Properties so as to restore compliance
hereunder.
(b) Simultaneously with the delivery of each Reserve Report pursuant to
Section 5.08, the Issuer shall deliver to each Holder a calculation of the
Annual Coverage Ratio for each of (x) in the case of a Reserve Report
evaluating reserves as of December 31, the fiscal year commencing on the
day immediately succeeding such December 31 and the next two succeeding
fiscal years and (y) in the case of a Reserve Report evaluating reserves as
of June 30, the fiscal year commencing on the next succeeding January 1 and
the immediate following fiscal year.
ARTICLE III
Miscellaneous
SECTION 3.01. NEW YORK LAW. THIS AMENDMENT SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED BY THE LAW OF THE STATE OF NEW YORK.
SECTION 3.02 Ratification. The Note Purchase Agreement as hereby amended
is in all respects ratified and confirmed, and all of the rights and powers
created thereby or thereunder shall be and remain in full force and effect.
2
<PAGE>
SECTION 3.03 Counterparts. This Amendment may be executed in any number
of counterparts and by the different parties hereto in separate counterparts,
each of which when so executed and delivered shall be deemed to be an original
and all of which taken together shall constitute but one and the same
instrument.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
duly executed by their respective authorized officers as of the date first above
written.
CABOT OIL & GAS CORPORATION
By: /s/ Roger J. Klatt
---------------------
Title: Vice President
----------------
THE NORTHWESTERN MUTUAL LIFE
By: /s/ A. K. Koyky
------------------
Title: Vice President
----------------
MASSACHUSETTS MUTUAL LIFE INSURANCE
COMPANY
By: /s/ John B. Joyce
--------------------
Title: Vice President
----------------
THE MUTUAL LIFE INSURANCE COMPANY OF
NEW YORK
By: s/s/ Diane Hom
----------------
Title: Managing Director
-------------------
UNUM LIFE INSURANCE COMPANY OF AMERICA
By: /s/ John P. Berry
-------------------
Title: Director, Corporate Securities
--------------------------------
3
<PAGE>
NEW ENGLAND MUTUAL LIFE INSURANCE
COMPANY
By: /s/ Michael T. Zonghetti
--------------------------
Title: Vice President
-----------------
NATIONAL LIFE INSURANCE COMPANY
By: /s/ Scott Higgins
-------------------
Title: Vice President
----------------
KEYSTONE PROVIDENT LIFE INSURANCE
COMPANY
By: Stein Roe & Farnham Inc., as Agent
By: /s/ Donovan J. Paul
---------------------
Title: Senior Vice President
----------------------
THE OHIO NATIONAL LIFE INSURANCE
COMPANY
By: /s/ Michael A. Boedeker
-------------------------
Title: Vice President
----------------
SOUTHERN FARM BUREAU LIFE INSURANCE
COMPANY
By: Douglas Folk
-------------
Title: Assistant Portfolio Manager
-----------------------------
4
<PAGE>
EXECUTED ORIGINAL
------------------
Exhibit 4.6(b)
SECOND AMENDMENT TO THE NOTE PURCHASE AGREEMENT
SECOND AMENDMENT dated as of July 6, 1994 among CABOT OIL & GAS CORPORATION
(the "Issuer") and the Purchasers listed on the signature pages hereof (the
"Purchasers").
W I T N E S S E T H :
WHEREAS, the parties hereto have heretofore entered into a Note Purchase
Agreement dated as of May 11, 1990, as amended by a First Amendment dated as of
June 28, 1991 (the "Purchase Agreement") in connection with the issuance of
$80,000,000 of 10.18% Notes due 2002; and
WHEREAS, the parties hereto desire to amend the Purchase Agreement as
set forth below.
NOW, THEREFORE, the parties hereto agree as follows:
SECTION 1. Definitions; References. Unless otherwise specifically
defined herein, each term used herein which is defined in the Purchase Agreement
shall have the meaning assigned to such term in the Purchase Agreement.
SECTION 2. Amendment to Agreement. Section 5.04 Conduct of Business
and Maintenance of Existence; Location of Reserves is hereby amended by (i)
deleting the words "Location of Reserves" from the heading and (ii) deleting
subsection (c) in its entirety.
SECTION 3. NEW YORK LAW. THIS AMENDMENT SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW YORK.
SECTION 4. Ratification. The Purchase Agreement as hereby amended is
in all respects ratified and confirmed, and all of the rights and powers created
thereof or thereunder shall be and remain in full force and effect.
SECTION 5. Counterparts. This Amendment may be signed in any number
of counterparts, each of which shall be an original, with the same effect as if
the signatures thereto and hereto were upon the same instrument.
IN WITNESS WHEREOF, the parties hereto have caused this Second
Amendment to the Note Purchase Agreement to be duly executed as of the date
first above written.
<PAGE>
CABOT OIL & GAS CORPORATION
By: /s/ John U. Clarke
------------------------------------
Title: Executive Vice President and
Chief Financial Officer
THE NORTHWESTERN MUTUAL LIFE
INSURANCE COMPANY
By: /s/ A. K. Koyky
-----------------------------------
Title: Vice President
MASSACHUSETTS MUTUAL LIFE
INSURANCE COMPANY
By: /s/ John B. Joyce
-----------------------------------
Title: Vice President
THE MUTUAL LIFE INSURANCE
COMPANY OF NEW YORK
By: /s/ Peter W. Oliver
-----------------------------------
Title: Managing Director
PACIFIC MUTUAL INSURANCE COMPANY
By: /s/ William R. Schmidt
-----------------------------------
Title: Assistant Vice President
2 of 3
<PAGE>
NEW ENGLAND MUTUAL LIFE INSURANCE
COMPANY
By: Hanson C. Robbins
-----------------------------------
Title: Senior Investment Officer
NATIONAL LIFE INSURANCE
COMPANY
By: R. Scott Higgins
-----------------------------------
Title: Vice President
KEYSTONE PROVIDENT LIFE INSURANCE
COMPANY
By:
___________________________________
Title:
THE OHIO NATIONAL LIFE INSURANCE
COMPANY
By: Michael A. Boedeker
-----------------------------------
Title: Vice President
SOUTHERN FARM BUREAU LIFE
INSURANCE COMPANY
By:
___________________________________
Title:
3 of 3
<PAGE>
EXHIBIT 13
CABOT OIL & GAS CORPORATION
SELECTED HISTORICAL FINANCIAL DATA
The following table sets forth a summary of selected consolidated financial
data for the Company for the periods indicated. This information should be read
in conjunction with Management's Discussion and Analysis of Financial Condition
and Results of Operations and the Consolidated Financial Statements and related
Notes thereto.
<TABLE>
<CAPTION>
Three
Months Year
Ended Ended
Year Ended December 31, December September
----------------------------------------- 31, 30,
1994 1993 1992 1991 1990 1990
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Income Statement Data:
Revenues.............................. $237,067 $164,295 $147,608 $140,484 $ 48,519 $128,621
Income from Operations................ 15,013 20,007 17,983 13,707 13,047 18,889
Net Income (Loss) Applicable to All
Common Stockholders.................. (5,444) 2,088 2,227 229 7,224 11,697
Earnings (Loss) Per Share Applicable
to All Common Stockholders:
Historical (1)...................... $ (0.25) $ 0.10 $ 0.11 $ 0.01 $ 0.35 $ 0.57
Pro Forma (Unaudited) (2)........... 0.27
Dividends Per Common Share............ $ 0.16 $ 0.16 $ 0.16 $ 0.16 $ 0.04 $ 0.08
Balance Sheet Data:
Oil and Gas Properties................ $554,137 $322,163 $229,778 $229,538 $217,937 $212,251
Total Assets.......................... 688,352 445,001 348,696 334,311 320,740 302,107
Long-Term Debt........................ 268,363 169,000 120,000 105,000 91,500 80,000
Stockholders' Equity.................. 243,082 153,529 118,313 119,241 121,933 114,912
</TABLE>
-----------
(1) See "Earnings Per Common Share" under Note 1. of the Notes to the
Consolidated Financial Statements.
(2) Adjusted to reflect the effect as though the Company's IPO had occurred on
October 1, 1989.
1
<PAGE>
CABOT OIL & GAS CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following review of operations should be read in conjunction with the
Consolidated Financial Statements and the Notes thereto included elsewhere.
OVERVIEW
The Company continued its growth strategy in 1994 through the acquisition of
oil and gas producing properties with substantial upside potential, the
exploitation of current development drilling opportunities and the expansion of
marketing activities, especially in the purchase and resale of natural gas.
During 1994, significant progress was made toward the achievement of this
strategy. Approximately $185 million of proved properties were acquired,
primarily in the Rocky Mountain and Gulf Coast areas of the United States,
giving the Company an expanded base of production, development and exploration
opportunities outside its historical core areas in the Appalachian and Anadarko
Basins. The Company actively developed properties in those basins,
concentrating on locations provided by the 1993 acquisitions from Emax Oil
Company ("Emax") and Harken Anadarko Partners, L.P. ("Harken"). Also, the
Company's marketing activity in the purchase and resale of natural gas more than
doubled compared with 1993.
. On May 2, 1994, the acquisition of Washington Energy Resources Company
(WERCO) via a merger into a Company subsidiary was completed in a tax-free
exchange. Total capitalized costs related to this acquisition were $216.2
million, comprised of cash and stock consideration of $176.0 million
(subject to certain adjustments) and a $40.2 million non-cash component
relating to deferred taxes for the difference between the tax and book
bases of the acquired properties, as required by Statement of Financial
Accounting Standards ("SFAS") 109, "Accounting for Income Taxes". Eight
months of operating results from the acquisition were reflected in 1994,
including 12.5 Bcfe of production, $42.1 million of revenues and $14.3
million of discretionary cash flow. The WERCO acquisition provides
significant development and exploration opportunities in the Green River
Basin of Wyoming and in South Texas, the addition of 191 Bcfe of proved
reserves, and expansion of the Company's production and future development
base.
. The Company drilled 169 net wells with a drilling success rate of 92%, which
compares with 150 net wells drilled in
2
<PAGE>
1993 at a success rate of 92%. The focus of this development effort was on
property acquired in 1993, and illustrates the Company's commitment to
developing the upside drilling potential of its acquisitions.
. Natural gas sales exceeded 102 Bcf in 1994, an increase of 38 Bcf, or 59%,
over 1993. This increase was the result of two factors: increased
production and an expanded marketing program with respect to third-party
natural gas purchased for resale.
Natural gas production increased 12.3 Bcf, 9.5 Bcf of which was due to
production associated with the WERCO acquisition.The remainder represented
increased production, primarily as a result of the development of
Appalachian properties acquired in 1993 from Emax, and a full year's
production on producing properties acquired from Emax.
The Company's expanded marketing effort increased purchase and resale
volumes of third-party natural gas by 26.7 Bcf, or 124%, from 1993. The
most significant part of this increase was in natural gas purchased and
resold in back-to-back, or brokered, arrangements, which increased from 7.4
Bcf in 1993 to 23.7 Bcf in 1994. The Company realized a contribution to
operating income from these brokered arrangements of approximately 5 cents
per Mcf in 1994, compared with approximately 4 cents per Mcf in 1993.
As a hedging strategy to manage commodity price risk associated with its
production and purchase commitments, from time to time the Company enters
into commodity derivative contracts, such as natural gas price swaps (see
Notes 1. and 15. of the Notes to the Consolidated Financial Statements).
The Company's strategic pursuits are sensitive to energy commodity prices,
particularly the price of natural gas. The average natural gas price realized
by the Company in 1994 was approximately 11% lower than 1993. Lower natural gas
prices and higher financing costs, offset in part by the benefits of higher
production and sales volumes and lower unit costs, reduced earnings and cash
flows. The $5.4 million net loss reported for 1994 was due in part to the
decline in natural gas prices that began in the third quarter and continued into
the fourth quarter. The average natural gas price for the second half of 1994
declined $0.48 per Mcf, or 20%, compared with the same period for 1993. Gas
prices have remained depressed into early 1995 with industry analysts
forecasting minimal or no improvement in prices in the short term. Because of
this challenging price environment, the Company has adjusted its plans for 1995
as follows:
3
<PAGE>
. Cash flow is expected to be maximized by reducing capital spending to
concentrate only on the highest potential return opportunities, and by
selling selective non-core properties, with excess cash being applied to
debt reduction;
. As of January 1995, management of the Company's Rocky Mountain, Anadarko
and onshore Gulf Coast areas has been consolidated into a single Western
Region; and
. Operating and corporate office expenses are expected to decrease by a
reduction of approximately 15% of the Company's employees.
These steps are expected to reduce costs by approximately $3 million in 1995
and $4 million a year thereafter. The cost of these steps will be recorded as a
one-time charge to earnings of $3.5 million, or 15 cents per share, during the
first quarter of 1995. The Company believes these steps are appropriate in the
current price environment, and should enable the Company to pursue its strategic
objectives over the long term.
FINANCIAL CONDITION
CAPITAL RESOURCES AND LIQUIDITY
The Company's capital resources consist primarily of cash flows from oil and
gas properties and asset-based borrowing supported by its oil and gas reserves.
The Company's level of earnings and cash flows depends on many factors,
including the price of natural gas and oil and its ability to control or reduce
costs. Demand for oil and gas has historically been subject to seasonal
influences characterized by peak demand and higher prices in the winter heating
season. During 1994, the Company did not experience significant curtailments
of production due to market conditions. However, during the month of October
1994, the Company elected to withhold approximately 25 Mmcf per day of natural
gas from markets, or about 13% of its productive capacity, due to low prices,
which had the effect of reducing cash flows for the month.
Primary sources of cash for the Company during the three-year period ended
December 31, 1994 were funds generated from operations and bank borrowing.
Primary uses of cash for the same period were funds used in operations,
exploration and development expenditures, acquisitions, repayment of debt and
dividends.
The Company had a net cash inflow of $0.9 million in 1994. Net cash inflow
from operating and financing activities totalled $159.7 million, funding capital
and exploration expenditures of $159.2 million, including the $78.5 million cash
component of total consideration attributable to the WERCO acquisition.
4
<PAGE>
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(in millions)
<S> <C> <C> <C>
Cash Flows Provided by Operating Activities $ 67.3 $ 55.4 $ 27.9
======= ======= =======
</TABLE>
Cash flows provided by operating activities in 1994 were higher by $11.9
million compared with 1993 primarily due to the cash flows generated from the
oil and gas properties acquired in the WERCO acquisition.
Cash flows provided by operating activities in 1993 were higher than 1992 by
$27.5 million primarily due to a higher funding requirement of working capital
in 1992 (attributable to an $8.8 million increase in accounts receivable due to
prices and timing).
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(in millions)
<S> <C> <C> <C>
Cash Flows Used by Investing Activities $ 158.8 $ 98.9 $ 42.5
======== ======= =======
</TABLE>
Cash flows used by investing activities in 1994 were $59.9 million higher
than in 1993 primarily due to $52.9 million of increased capital expenditures
from development drilling activity and the WERCO acquisition.
Cash flows used by investing activities in 1993 were $56.4 million higher than
in 1992 primarily due to increased capital expenditures, most notably the Emax
acquisition for $46.4 million. Also, the Company lowered its capital spending
in 1992 primarily in response to a decline in natural gas prices in the first
half of the year.
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(in millions)
<S> <C> <C> <C>
Cash Flows Provided by Financing Activities $ 92.4 $ 45.3 $ 13.5
======= ======= =======
</TABLE>
Cash flows provided by financing activities from 1992 to 1994 were primarily
borrowings under the Company's revolving credit facility. In 1994 the Company's
debt under this facility increased $99 million, including $78.5 million to
partially fund the WERCO acquisition, $6.2 million to purchase additional
drilling locations in connection with the Emax acquisition, and $7.1 million for
other property acquisitions and capital expenditures. The increase in 1993 over
1992 was primarily attributable to indebtedness incurred to finance the Emax
acquisition.
At December 31, 1994 the available credit line under the Company's revolving
credit facility was $260 million, or $80 million higher than 1993, due to the
additional value associated with the WERCO acquisition and reserve additions
from the Company's drilling program. The available credit line is subject
5
<PAGE>
to adjustment on the basis of the projected present value of estimated future
net cash flows from proved oil and gas reserves (as determined by an independent
petroleum engineer's report incorporating certain assumptions provided by the
lender) and other assets. The Company's outstanding indebtedness under the
revolving credit facility was $188 million at December 31, 1994.
The Company's 1995 debt service is projected to be approximately $25 million.
No principal payments are due in 1995.
The Company entered into reverse interest rate swap agreements in 1993 with
four banks that effectively converted the Company's $80 million fixed-rate notes
into variable-rate notes. Under the reverse swap agreements, the Company pays a
variable rate of interest which is based on the six-month London Interbank
Offering Rate. The banks pay the Company fixed rates of interest that average
5.00%. The difference paid or received under such agreements is charged or
credited to interest expense over the life of the agreements. The four
agreements have notional principal of $20 million each, with terms of two,
three, four and five years. In 1994, the Company recorded a $0.4 million net
increase to interest expense in connection with these interest rate swaps.
Because of the effect of increasing interest rates on these swaps, in January
1995, the Company entered into four additional swap agreements which effectively
fixed interest payments on the original interest rate swaps until May 1997. As
a result of these transactions, the Company will record a $4.4 million increase
in interest expense over the period of the additional swaps. Added interest
expense, presently estimated at $0.4 million, may be incurred on the original
swaps after the additional swaps terminate if current interest rate projections
are realized.
Capitalization information on the Company is as follows:
<TABLE>
<CAPTION>
1994 1993 1992
-------- -------- --------
(in millions)
<S> <C> <C> <C>
Long-Term Debt.......... $268.3 $169.0 $120.0
Stockholders' Equity
Common Stock....... 151.8 118.9 118.3
Preferred Stock.... 91.3 34.6 -
------ ------ ------
Total......... 243.1 153.5 118.3
------ ------ ------
Total Capitalization.... $511.4 $322.5 $238.3
====== ====== ======
Debt to Capitalization.. 52.5% 52.4% 50.4%
====== ====== ======
</TABLE>
The Company's capitalization reflects the financing of the WERCO
acquisition, which closed on May 2, 1994. The Company incurred debt of $78.5
million and issued 1,134,000 shares of 6% convertible redeemable preferred stock
($50 per share stated
6
<PAGE>
value) and 2,133,000 shares of common stock in connection with the acquisition.
CAPITAL AND EXPLORATION EXPENDITURES
The following table presents major components of capital and exploration
expenditures for the three years ended December 31, 1994.
<TABLE>
<CAPTION>
1994 1993 1992
-------- ------- ------
(in millions)
<S> <C> <C> <C>
Capital Expenditures:
Drilling and Facilities....... $ 47.9 $ 34.6 $19.9
Leasehold Acquisitions........ 4.7 3.9 1.9
Pipeline and Gathering........ 8.9 6.8 8.2
Other......................... 2.3 1.3 5.4
------ ------ -----
63.8 46.6 35.4
------ ------ -----
Proved Property Acquisitions.. 8.9 82.4(1) 1.6
WERCO Acquisition............. 216.2(2) - -
------ ----- ---
225.1 82.4 1.6
------ ------ -----
Exploration Expenses............ 8.0 6.9 6.2
------ ------ -----
Total......................... $296.9 $135.9 $43.2
====== ====== =====
</TABLE>
-------------
(1) Includes $34.6 million of non-cash consideration for the purchase of
properties from Harken.
(2) Included in capital expenditures for the WERCO acquisition was $97.5
million in common and preferred stock of the Company and a $40.2 million non-
cash component relating to deferred taxes for the difference between the tax and
book bases of the acquired properties, as required by SFAS 109, "Accounting for
Income Taxes".
In May 1994, the Company completed the acquisition of WERCO, formerly a
wholly-owned subsidiary of Washington Energy Company. The Company acquired the
stock of WERCO in a tax-free exchange. The acquisition was recorded using the
purchase method. Excluded from the transaction were certain firm
transportation, storage and other contractual arrangements of WERCO's marketing
affiliate which were retained by Washington Energy Company.
The Company issued 2,133,000 shares of common stock and 1,134,000 shares of 6%
convertible redeemable preferred stock ($50 per share stated value) to
Washington Energy Company in exchange for the capital stock of WERCO. The
preferred stock is convertible into 1,972,174 shares of common stock at $28.75
per share. In addition, the Company advanced cash to repay intercompany
indebtedness between WERCO and Washington Energy Company of $63.7 million.
As of the acquisition date, the oil and gas properties,
7
<PAGE>
located in the Green River Basin of Wyoming and the onshore Gulf Coast included
483 wells (134 net), and approximately 191 Bcfe of proved reserves, of which 82%
was natural gas and 84% was developed. Average net daily production from these
properties in 1994 was approximately 39.2 million cubic feet of natural gas,
1,500 barrels of oil and 550 barrels of natural gas liquids.
The Company continued further development of its 1993 property acquisitions
from Harken and Emax. The Company purchased 56 additional drilling locations
from Emax for $6 million and spent $11 million to drill 69 wells in 1994, adding
16 Bcfe of proved reserves. Exploration and development expenditures were $2.8
million on the Harken acquisition in 1994. Recoverable reserves on the Harken
acquisition have improved by 31% to 59 Bcfe since the purchase date, as a result
of discovering drilling opportunities beyond those identified at the time of the
acquisition and enhancing production on producing properties acquired.
Total capital and exploration expenditures in 1994 increased $161 million
compared to 1993 primarily due to the WERCO acquisition discussed above.
Drilling and facilities expenditures were $13.3 million higher than 1993 largely
due to the expanded drilling program.
The $92.7 million increase in capital and exploration expenditures in 1993
compared to 1992 was due primarily to the $84.6 million of oil and gas
properties acquired from Emax and Harken.
The Company generally funds its capital and exploration activities, excluding
oil and gas property acquisitions, with cash generated from operations and
budgets such capital expenditures based upon projected cash flows, exclusive of
acquisitions.
Planned expenditures for 1995 have been significantly reduced compared with
1994 due to the precipitous fall of natural gas prices in the second half of
1994 and the depressed short-term price outlook for 1995. Depending on the
level of future natural gas prices, the Company intends to review and adjust the
capital and exploration expenditures planned for 1995 as industry conditions
dictate. Presently, the Company projects $25 to $30 million in capital and
exploration expenditures for 1995. The Company plans to drill 40 to 60 wells
(20 to 30 net), compared with 208 wells (169.1 net), drilled in 1994. Capital
dedicated to the drilling program for 1995 is $10 to $15 million.
Other 1995 capital expenditures are planned primarily for producing property
acquisitions and for gathering and pipeline infrastructure maintenance and
construction.
8
<PAGE>
During 1994, dividends were paid on the Company's common stock totalling $3.5
million, on the $3.125 convertible preferred stock totalling $2.2 million, and
on the 6% convertible redeemable preferred stock totalling $1.4 million. The
Company has paid quarterly common stock dividends of $0.04 per share since
becoming publicly traded in 1990. The amount of future dividends is determined
by the Board of Directors and is dependent upon a number of factors, including
future earnings, financial condition, and capital requirements.
OTHER ISSUES AND CONTINGENCIES
Hancock Settlement. Effective December 1, 1994, the Company reached a
settlement with John Hancock Mutual Life Insurance Company ("John Hancock")
which resolved a 1992 claim asserted by John Hancock. The settlement provides
for the exchange between John Hancock and the Company of interests in certain
proved oil and gas properties. The Company transferred partial working
interests in certain wells located in West Virginia to John Hancock in exchange
for partial working interests in certain wells located in Pennsylvania and New
York. The Company continues to operate all of these properties. As an exchange
of interests in oil and gas properties, the Company's net book basis in the
property interests transferred to John Hancock became the basis for the property
interests received from John Hancock. Accordingly, no gain or loss was
recognized in the exchange.
Barby Lawsuit. In February 1993, Barby Energy Corporation and certain other
parties filed suit in Beaver County, Oklahoma against the Company to determine
the rights and interests of the parties in and to the oil, gas and other
minerals underlying a tract of land in Beaver County, Oklahoma, to quiet title
to said mineral estate, and for an accounting and payment of production proceeds
attributable to said mineral estate. Specifically at issue was whether there
was continuous production from an oil and gas well located on the property at
issue since July 5, 1965. Plaintiffs claimed there was a cessation of
production, and therefore, all right, title and interest to such property
reverted to them and they were entitled to all revenues from such production
since the date cessation of production occurred. The Company maintained that it
holds a valid oil and gas lease covering the interest claimed by the plaintiffs.
The trial commenced on February 6, 1995 and, pursuant to an order entered on
February 13, 1995, the judge denied and overruled all of the plaintiffs' claims.
The decision of the judge may be appealed by the plaintiffs.
Corporate Income Tax. The Company is a beneficiary of tax credits for the
production of certain qualified fuels, including natural gas produced from tight
formations and Devonian Shale. The credit for natural gas from a tight
formation ("tight gas sands") amounts to $0.52 per Mmbtu for natural gas sold
prior to
9
<PAGE>
2003 from qualified wells drilled in 1991 and 1992. A number of wells drilled
in the Appalachian Region during 1991 and 1992 qualified for the tight gas sands
tax credit. The credit for natural gas produced from Devonian Shale is
approximately $1.01 per Mmbtu in 1994. As a result of the WERCO acquisition,
certain production from qualifying formations in the Rocky Mountains also
qualifies for the tight gas sands tax credit. However, the benefits of all such
credits have been, and may continue to be, lost or deferred depending on the
amount of regular taxable income earned by the Company. Under current tax
provisions, the Company expects to benefit by the carryforward of credits that
become a part of the minimum tax credit carryforward.
The Company may benefit in 1995 and in the future from the alternative minimum
tax ("AMT") relief granted under the Comprehensive National Energy Policy Act of
1992. The Act repealed provisions of the AMT requiring a taxpayer's alternative
minimum taxable income to be increased on account of certain intangible drilling
costs ("IDCs") and percentage depletion deductions. The repeal of these
provisions generally applies to taxable years beginning after 1992. The repeal
of the excess IDC preference cannot reduce a taxpayer's alternative minimum
taxable income by more than 40% (30% for 1993) of the amount of such income
determined without regard to the repeal of such preference.
FERC Order 636. The marketing of natural gas has changed significantly as a
result of Order 636 (the "Order"), which was issued by the Federal Energy
Regulatory Commission in 1992. The Order required interstate pipelines to
unbundle their natural gas sales, storage and transportation services. As such,
local distribution companies and end users will separately contract these
services from natural gas marketers and producers. The Order has had the effect
of creating greater competition in the industry and also has provided the
Company the opportunity to expand its marketing effort. In 1993 and 1994, there
was an increase in the number of third-party producers who use the Company to
market their natural gas and in margin pressures from increased competition for
markets. The Order also appears likely to increase gathering charges by various
pipeline companies used by the Company to gather and transport natural gas.
Environmental Regulation. The Company operates under numerous state and
federal laws regulating the discharge of materials into, and the protection of,
the environment, including the Federal Clean Air Act. In the ordinary course of
business, the Company conducts an ongoing review of the effect of these various
environmental laws on its business and operations. It is impossible to
determine whether and to what extent the Company's future performance may be
affected by environmental laws; however, management does not believe that such
laws will have a material adverse effect on the Company's financial position or
10
<PAGE>
results of operations.
Restrictive Covenants. The Company's ability to incur debt, to pay dividends
on its common and preferred stock, and to make certain types of investments is
dependent upon certain restrictive debt covenants in the Company's various debt
instruments. Among other requirements, the Company's revolving credit facility
specifies a minimum cash flow to debt service coverage ratio of 1.2 to 1.0 for
the current year and estimated for the next two years. In 1994, the Company's
cash flow to debt service coverage ratio, using cash flow estimates provided by
the agent bank, was 4.2 to 1.0. For 1995 and 1996, the ratio is estimated to be
2.8 to 1.0 and 2.7 to 1.0, respectively.
CONCLUSION
The Company's financial results depend upon many factors, particularly the
price of natural gas and its ability to market its production on economically
attractive terms. The Company's average 1994 natural gas price decreased 11%
compared with the average natural gas price received in 1993. The deterioration
of gas prices during 1994 has negatively impacted the Company's earnings and
cash flows and has contributed significantly to the net loss recorded in 1994.
Given the volatility of natural gas prices in recent years, management cannot
predict with certainty what pricing levels will be for the remainder of 1995.
However, the Company believes the continuing effects of lower prices will
negatively impact earnings and cash flows and will probably result in a net loss
for the first quarter of 1995. Because future cash flows and earnings are
subject to such variables, there can be no assurance that the Company's
operations will provide cash sufficient to fully fund its capital requirements.
While the Company has adopted a long-term plan to pursue potential
acquisitions as part of its stated corporate strategy, such acquisitions may
require capital resources beyond those provided from operations. The Company's
ability to fund such acquisitions, if necessary, with external financing is
dependent, among other things, upon available borrowing capacity under its
committed bank line and the Company's access to and the general conditions of
debt and equity markets.
As described earlier, the Company's 1995 plans include a reduction in capital
spending and other cost reduction measures enacted to ensure financial stability
in the short term. Depending upon industry conditions in 1995, the Company
might take further steps to ensure the availability of capital, including, among
other things, further reductions in capital expenditures or the reduction of the
common stock dividend.
11
<PAGE>
The Company believes that higher production volumes and natural gas prices
over time coupled with the Company's continuing efforts to reduce costs will
return the Company to profitability. Furthermore, the Company believes its
capital resources, supplemented, if necessary, with external financing, are
adequate to meet its capital requirements, including acquisitions.
12
<PAGE>
RESULTS OF OPERATIONS
For the purpose of reviewing the Company's results of operations, "Net Income
(Loss)" is defined as net income (loss) applicable to common stockholders. The
Company merged its newly acquired holdings from the WERCO acquisition, located
in the Rocky Mountains and the onshore Gulf Coast, with the Company's holdings
in the Anadarko Region to form the "Western Region".
SELECTED FINANCIAL AND OPERATING DATA
<TABLE>
<CAPTION>
1994 1993 1992
------------- ---------- ----------
(in millions except where specified)
<S> <C> <C> <C>
Revenues............................... $237.1 $164.3 $147.6
Costs and Expenses..................... 222.1 145.6 130.2
Interest Expense....................... 16.7 10.3 9.8
Net Income (Loss)...................... (5.4) 2.1 2.2
Earnings (Loss) Per Share.............. $(0.25) $ 0.10 $ 0.11
Natural Gas Sales (Bcf)
Appalachia........................... 56.9 39.9 40.7
West................................. 45.6 24.5 23.8
------ ------ ------
Total Company........................ 102.5 64.4 64.5
====== ====== ======
Natural Gas Production (Bcf)
Appalachia........................... 29.7 26.2 25.6
West................................. 28.6 19.8 19.9
------ ------ ------
Total Company........................ 58.3 46.0 45.5
====== ====== ======
Natural Gas Prices ($/Mcf)
Appalachia........................... $ 2.47 $ 2.69 $ 2.50
West................................. $ 1.73 $ 1.94 $ 1.62
Total Company........................ $ 2.14 $ 2.40 $ 2.18
Crude/Condensate
Volume (Mbbl)....................... 687 345 162
Price ($/Bbl)....................... $16.66 $16.58 $19.03
</TABLE>
The table below presents the effects of certain selected items ("selected
items") on the Company's results of operations for the three years ended
December 31, 1994.
<TABLE>
<CAPTION>
1994 1993 1992
------ ------ ------
(in millions)
<S> <C> <C> <C>
Net Income (Loss) Before Selected Items............... $(5.4) $ 5.1 $ 6.4
Early adoption of SFAS 112.......................... (0.4)
Consolidation of office space....................... (0.3)
Deferred tax adjustment due to federal rate change.. (2.3)
Early adoption of SFAS 106.......................... (1.5)
Settlement of Cabot tax dispute..................... (2.7)
----- ----- -----
Net Income (Loss)..................................... $(5.4) $ 2.1 $ 2.2
===== ===== =====
</TABLE>
13
<PAGE>
1994 AND 1993 COMPARED
Net Income (Loss) and Revenues. The Company recorded a net loss in 1994 of
$5.4 million, down $10.5 million, or $0.48 per share, compared with 1993,
excluding the impact of the selected items. Excluding the pre-tax effects of
the selected items in the table above, operating income decreased $6.2 million
and revenues increased $72.8 million. Natural gas sales comprised 93%, or
$219.7 million, of total revenue in 1994. The increase in revenues was
primarily due to the WERCO acquisition ($42.1 million), an increase in natural
gas purchased for resale ($32.3 million) and an increase in core production
volumes ($5.9 million). Net income and operating income, however, were
negatively impacted in 1994 by an 11% decline in the average natural gas price
and higher depreciation expense and additional financing cost associated with
the WERCO acquisition.
The Company added two new operating areas through the WERCO acquisition in the
Rocky Mountains and onshore Gulf Coast. The WERCO acquisition provides the
Company with development and exploration opportunities in the Green River Basin
of the Rocky Mountains and in the onshore Gulf Coast; an increase in reserves
which now exceeds one trillion cubic feet equivalent of natural gas; and the
expansion of the Company's production base by approximately 40% annualized.
Operating results from the WERCO acquisition for the eight months ended December
31, 1994 were as follows: 9.5 Bcf of natural gas production, 19.4 Bcf of
natural gas sales, 357 Mbbl of oil production and $42.1 million of revenues.
Total natural gas and oil revenues were $33.7 million and $6.0 million,
respectively. The average natural gas price received on the WERCO acquisition
in 1994 was $1.74 per Mcf.
Natural gas sales volumes were up 17.0 Bcf to 56.9 Bcf in the Appalachian
Region primarily attributable to an increase in natural gas purchased for resale
and, to a lesser extent, increased production. Production volume was up 3.5 Bcf
to 29.7 Bcf in the Appalachian Region primarily due to expanded production
associated with the Emax acquisition. Production volume in the Western Region
was up 8.8 Bcf to 28.6 Bcf due to increased production associated with the WERCO
acquisition. Natural gas sales volumes in the Western Region were up 21 Bcf
primarily due to the increased production and, to a lesser extent, increased
volumes of natural gas purchased for resale.
The average Appalachian natural gas sales price decreased $0.22 per Mcf, or
8%, to $2.47, reducing operating revenues by approximately $12.3 million. In
the Western Region, the average natural gas sales price also decreased $0.21 per
Mcf, or 11%, to $1.73, reducing operating revenues by approximately $9.6
million. Lower spot market gas prices, both for Company production and the
increased volume of natural gas purchased for resale, along with a change in the
weighted mix of sales volumes due to sales from
14
<PAGE>
new operating areas, were the primary reasons the Company's overall weighted
average natural gas sales price decreased $0.26 per Mcf to $2.14 compared with
1993.
Crude oil and condensate sales increased 342 Mbbl to 687 Mbbl due primarily to
the Harken acquisition (89 Mbbl) and the WERCO acquisition (357 Mbbl).
Costs and Expenses. Total costs and expenses increased $76.5 million, or
53%, to $222.1 million primarily due to expanded operations associated with the
WERCO acquisition and an increase in natural gas purchased for resale:
. The cost of natural gas purchases increased $48.3 million to $96.8
million. The WERCO acquisition increased this cost by $18.0 million.
The remaining $30.3 million primarily was due to a 15.1 Bcf increase in
natural gas purchased for resale, net of storage.
. Direct operations expenses increased $4.7 million, or 16%, primarily due
to $3.7 million of operating expenses attributable to the WERCO
acquisition and $1.6 million increased operating expenses attributable to
the first full year of operations on the Emax and Harken acquisitions.
Direct operations expense per Mcfe of production decreased $0.07, or 12%,
to $0.53 due to increased production primarily attributable to the WERCO
acquisition.
. Exploration expense increased $1.1 million due to the WERCO acquisition.
. Depreciation, depletion, amortization and impairment expense increased
$20.1 million, or 58%, primarily due to the Harken, Emax and WERCO
acquisitions. DD&A and impairment expense per Mcfe of production
increased $0.15, or 21%, to $0.86 due primarily to the acquisitions in
general and further affected by the required accounting treatment of the
tax free nature of the WERCO acquisition.
. General and administrative expenses decreased $0.7 million, or 4%,
excluding $0.4 million attributable to the WERCO acquisition, primarily
due to reduced fringe benefit and employee-related expenses. General and
administrative expenses per Mcfe of production decreased $0.09, or 25%,
to $0.27 due to the expanded production base, primarily from the WERCO
acquisition.
. Taxes other than income increased $2.7 million, or 28%, primarily due to
the WERCO acquisition. This expense remained virtually unchanged on a
unit of production
15
<PAGE>
basis.
Interest expense increased $6.3 million, or 61%, primarily due to a $99
million debt increase and an increase in the interest rate attributable to the
Company's revolving credit facility. The WERCO acquisition and the purchase of
additional drilling locations in connection with the Emax acquisition accounted
for $84.7 million, or 86%, of the debt increase.
Income tax expense decreased $6.8 million (to a $0.6 million benefit) due to
the decrease in 1994 earnings before income taxes and a $2.9 million charge in
the third quarter of 1993 to record an increase in the federal income tax rate.
The dividend requirement on preferred stock increased $3.0 million due
primarily to the $2.3 million associated with the 6% convertible redeemable
preferred stock issued in connection with the WERCO acquisition. The remaining
$0.7 million increase was attributable to the $3.125 cumulative convertible
preferred stock, issued May 3, 1993, for which only 8 months of dividends were
reflected in the corresponding period of 1993.
1993 AND 1992 COMPARED
Net Income and Revenues. Net income, excluding the impact of the selected
items, was $1.3 million, or $0.06 per share, lower than 1992. Excluding the
pre-tax effects of the selected items, income from operations was $0.8 million
higher. Operating revenues increased $16.7 million, or 11%, in 1993. Natural
gas sales made up 94%, or $154.8 million, of operating revenue. The increase in
operating revenues was caused primarily by an increase in the average natural
gas price.
Natural gas sales volumes were down 0.8 Bcf to 39.9 Bcf in the Appalachian
Region. Production volume in the Appalachian Region was up 0.6 Bcf, or 2%,
primarily due to the Emax acquisition. Production volume in the Western Region
was down 1.7 Bcf, or 9%, excluding 1.7 Bcf of production from the Harken
acquisition. Natural gas sales volumes in the Western Region were down 1.0 Bcf,
excluding 1.7 Bcf of sales from the Harken acquisition. The decrease in the
Western Region was primarily attributable to insufficient replacement well
production necessary to offset the significant production declines on several
wells drilled in 1990 that produced high volumes over a short period of time.
The average Appalachian natural gas sales price increased $0.19 per Mcf, or
8%, to $2.69, increasing operating revenues by approximately $7.6 million. In
the Western Region, the average natural gas sales price increased $0.32 per Mcf,
or 20%, to $1.94, increasing operating revenues by approximately $7.8 million.
Due to the weighted mix of sales volume, the overall weighted average natural
gas sales price increased $0.22 per Mcf,
16
<PAGE>
or 10%, to $2.40.
Crude oil and condensate sales increased 183 Mbbl, or 113%, due primarily to
the Harken acquisition.
Cost and expenses. Excluding the pre-tax effects of the selected items, total
costs and expenses increased $16.6 million, or 13%, primarily due to the
following:
. The cost of natural gas purchases increased $8.1 million, or 20%. The
increase was primarily due to a $0.19 per Mcf increase in the average price
of gas purchased for resale and a 1.7 Bcf increase in gas purchased for
resale and gas exchanges.
. Direct operations expenses increased $3.5 million, or 14%. Such expenses
included $0.8 million of relocation costs associated with the consolidation
of regional offices in the Appalachian Region and the Western Region, $1.7
million of operating expenses attributable to the Harken and Emax
acquisitions and $0.5 million of higher subsurface maintenance and pipeline
right-of-way maintenance costs.
. Exploration expense increased $0.7 million, or 11%, primarily due to
higher dry hole expenses.
. Depreciation, depletion, amortization and impairment expense increased $0.4
million, or 1%, excluding the $2.5 million attributable to the Harken and
Emax acquisitions.
. General and administrative expense decreased $1.1 million, or 7%,
excluding the impact of the $2.4 million charge for postretirement benefits
cost recorded in 1992 (a selected item). Effective January 1, 1992, the
Company elected the early adoption of SFAS 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions," and opted to amortize the
accumulated postretirement benefit obligation at January 1, 1992
("Transition Obligation") over 20 years. Due to an amendment of the
postretirement benefits plan, effective January 1, 1993, the amortization
cost of the unrecognized Transition Obligation for 1993 was significantly
reduced. The Company's total postretirement benefits cost for 1993 was
approximately $20 thousand.
. Taxes other than income increased $2.5 million, or 35%, due primarily to
higher taxes on production and reserves, as a result of higher natural gas
prices, and to the Harken and Emax acquisitions.
. Income tax expense increased $0.6 million, or 18%, and was caused
primarily by the increase in earnings before income tax.
17
<PAGE>
CABOT OIL & GAS CORPORATION
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of Cabot Oil & Gas Corporation:
We have audited the accompanying consolidated balance sheet of Cabot Oil & Gas
Corporation as of December 31, 1994 and 1993, and the related consolidated
statements of operations, stockholders' 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 consolidated financial position of Cabot Oil & Gas
Corporation as of December 31, 1994 and 1993, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 3, 1995
18
<PAGE>
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
REVENUES
Natural Gas..................................... $219,650 $154,792 $140,676
Crude Oil and Condensate........................ 11,445 5,715 3,088
Other........................................... 5,972 3,788 3,844
-------- -------- --------
237,067 164,295 147,608
COSTS AND EXPENSES
Costs of Natural Gas............................ 96,772 48,479 40,403
Direct Operations............................... 33,332 28,681 25,152
Exploration..................................... 8,014 6,943 6,227
Depreciation, Depletion and Amortization........ 51,040 31,621 27,966
Impairment of Unproved Properties............... 3,556 2,834 3,575
General and Administrative...................... 17,278 17,539 19,867
Taxes Other Than Income......................... 12,141 9,490 7,034
-------- -------- --------
222,133 145,587 130,224
GAIN ON SALE OF ASSETS.......................... 79 1,299 599
-------- -------- --------
INCOME FROM OPERATIONS.......................... 15,013 20,007 17,983
Interest Expense................................ 16,651 10,328 9,757
-------- -------- --------
INCOME (LOSS) BEFORE INCOME TAX EXPENSE......... (1,638) 9,679 8,226
Income Tax Expense (Benefit).................... (643) 6,159 5,999
-------- -------- --------
NET INCOME (LOSS)............................... (995) 3,520 2,227
Dividend Requirement on Preferred Stock......... 4,449 1,432 --
-------- -------- --------
Net Income (Loss) Applicable to Common
Stockholders.................................... $ (5,444) $ 2,088 $ 2,227
======== ======== ========
Earnings (Loss) Per Share Applicable to Common
Stockholders.................................. $(0.25) $0.10 $0.11
======== ======== ========
Average Common Shares Outstanding............... 22,018 20,507 20,465
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
19
<PAGE>
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS)
<TABLE>
<CAPTION>
December 31,
----------------------
1994 1993
------- --------
<S> <C> <C>
A S S E T S
CURRENT ASSETS
Cash and Cash Equivalents............................................ $ 3,773 $ 2,897
Accounts Receivable................................................. 38,166 35,296
Inventories......................................................... 8,384 5,693
Other............................................................... 1,696 752
-------- --------
Total Current Assets............................................... 52,019 44,638
PROPERTIES AND EQUIPMENT (Successful Efforts Method)................. 634,934 400,270
OTHER ASSETS......................................................... 1,399 93
-------- --------
$688,352 $445,001
======== ========
L I A B I L I T I E S A N D S T O C K H O L D E R S' E Q U I T Y
CURRENT LIABILITIES
Short-Term Debt..................................................... $ -- $ 530
Accounts Payable.................................................... 39,990 26,538
Accrued Liabilities................................................. 13,750 10,223
-------- --------
Total Current Liabilities.......................................... 53,740 37,291
LONG-TERM DEBT....................................................... 268,363 169,000
DEFERRED INCOME TAXES................................................ 117,807 78,698
OTHER LIABILITIES.................................................... 5,360 6,483
COMMITMENTS AND CONTINGENCIES (Note 10)
STOCKHOLDERS' EQUITY
Preferred Stock:
Authorized--5,000,000 Shares of $0.10 Par Value
Issued and Outstanding - $3.125 Cumulative Convertible Preferred;
$50 Stated Value; 692,439 Shares in 1994 and 1993..................
- 6% Convertible Redeemable Preferred; $50 Stated Value;
1,134,000 Shares in 1994........................................... 183 69
Common Stock:
Authorized--40,000,000 Shares of $0.10 Par Value
Issued and Outstanding--22,757,007 Shares and
20,583,220 Shares at December 31, 1994 and
1993, respectively................................................. 2,275 2,058
Class B Common Stock:
Authorized--800,000 Shares of $0.10 Par Value
No Shares Issued.................................................. -- --
Additional Paid-in Capital.......................................... 241,471 143,264
Retained Earnings (Deficit)......................................... (847) 8,138
-------- --------
Total Stockholders' Equity......................................... 243,082 153,529
-------- --------
$688,352 $445,001
======== ========
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
20
<PAGE>
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------
1994 1993 1992
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)................................ $ (995) $ 3,520 $ 2,227
Adjustments to Reconcile Net Income (Loss) to
Cash Provided (Used) by Operating Activities:
Depletion, Depreciation, and Amortization..... 54,596 34,455 31,541
Deferred Income Taxes......................... (796) 7,058 (1,344)
Gain on Sale of Assets........................ (79) (1,299) (599)
Exploration Expense........................... 8,014 6,943 6,227
Postretirement Benefits Other than Pension.... (866) (339) 2,460
Other, Net.................................... (669) (67) (20)
Changes in Assets and Liabilities:
Accounts Receivable........................... (2,870) (780) (8,847)
Inventories................................... (2,691) 65 (1,249)
Other Current Assets.......................... (944) (395) 178
Other Assets.................................. (1,306) 147 99
Accounts Payable and Accrued Liabilities...... 16,167 5,591 (3,314)
Other Liabilities............................. (258) 551 556
--------- -------- --------
Net Cash Provided By Operating Activities..... 67,303 55,450 27,915
--------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures............................. (72,684) (94,377) (36,966)
Cost of Major Acquisition........................ (78,525)(1) -- --
Proceeds from Sale of Assets..................... 400 2,410 653
Exploration Expense.............................. (8,014) (6,943) (6,227)
--------- -------- --------
Net Cash Used By Investing Activities............ (158,823) (98,910) (42,540)
--------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt................................. 125,833 67,720 29,810
Decrease in Debt................................. (27,000) (20,000) (13,000)
Exercise of Stock Options........................ 654 1,742 --
Dividends Paid................................... (7,091) (4,207) (3,275)
--------- -------- --------
Net Cash Provided By Financing Activities........ 92,396 45,255 13,535
--------- -------- --------
Net Increase (Decrease) in Cash and
Cash Equivalents................................. 876 1,795 (1,090)
Cash And Cash Equivalents,
Beginning Of Year................................ 2,897 1,102 2,192
--------- -------- --------
Cash and Cash Equivalents,
End of Year...................................... $ 3,773 $ 2,897 $ 1,102
========= ======== ========
-------------------------
</TABLE>
(1) Excludes non-cash consideration of $97.5 million of the Company's common
and preferred stock issued in connection with the WERCO Acquisition. See Note
13. WERCO Acquisition.
The accompanying notes are an integral part
of these consolidated financial statements.
21
<PAGE>
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
Retained
Common Preferred Paid-In Earnings
Stock Stock Capital (Deficit) Total
-------- --------- --------- --------- ----------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1991....... $2,046 -- $106,816 $10,379 $119,241
------ ---- -------- -------- ---------
Net Income......................... 2,227 2,227
Dividends Paid at $0.16 Per Share.. (3,275) (3,275)
Other.............................. 120 120
------ ---- -------- -------- ---------
Balance at December 31, 1992....... 2,046 -- 106,936 9,331 118,313
------ ---- -------- -------- ---------
Net Income......................... 3,520 3,520
Exercise of Stock Options.......... 12 1,730 1,742
Issuance of Preferred Stock........ 69 34,552 34,621
Preferred Stock Dividends
at $2.07 Per Share................. (1,432) (1,432)
Common Stock Dividends
at $0.16 Per Share................. (3,281) (3,281)
Other.............................. 46 46
------ ---- -------- -------- ---------
Balance at December 31, 1993....... 2,058 69 143,264 8,138 153,529
------ ---- -------- -------- ---------
Net Loss........................... (995) (995)
Exercise of Stock Options.......... 4 650 654
Issuance of Common Stock........... 213 40,546 40,759
Issuance of Preferred Stock........ 114 56,586 56,700
Preferred Stock Dividends
at $2.44 Per Share................. (4,449) (4,449)
Common Stock Dividends
at $0.16 Per Share................. (3,551) (3,551)
Tax Benefit of Stock Options....... 425 425
Other.............................. 10 10
------ ---- -------- -------- ---------
Balance at December 31, 1994....... $2,275 $183 $241,471 $ (847) $243,082
====== ==== ======== ======== =========
</TABLE>
The accompanying notes are an integral part
of these consolidated financial statements.
22
<PAGE>
CABOT OIL & GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
Cabot Oil & Gas Corporation, previously a subsidiary of Cabot Corporation
("Cabot"), was incorporated in Delaware in 1989 and became a 100% publicly-owned
company on April 25, 1991. Cabot Oil & Gas Corporation and subsidiaries (the
"Company") are engaged in the exploration, development, production and marketing
of natural gas and, to a lesser extent, crude oil and natural gas liquids. The
Company also transports, stores, gathers and purchases natural gas for resale.
The consolidated financial statements contain the accounts of the Company
after elimination of all significant intercompany balances and transactions.
The results of operations of oil and gas properties purchased in the acquisition
of Washington Energy Resources Company ("WERCO") have been included with those
of the Company since May 2, 1994 (see Note 13. WERCO Acquisition).
Pipeline Exchanges
Natural gas gathering and pipeline operations normally include exchange
arrangements with customers and suppliers. The volumes of natural gas due to or
from the Company under exchange agreements are recorded at average selling or
purchase prices, as the case may be, and are adjusted monthly to reflect market
changes. The net value of exchanged natural gas is included in inventories in
the consolidated balance sheet.
Properties and Equipment
The Company uses the successful efforts method of accounting for oil and gas
producing activities. Under this method, acquisition costs for proved and
unproved properties are capitalized when incurred. Exploration costs, including
geological and geophysical costs, the costs of carrying and retaining unproved
properties and exploratory dry hole drilling costs, are expensed. Development
costs, including the costs to drill and equip development wells, and successful
exploratory drilling costs that locate proved reserves, are capitalized. In
addition, the Company limits the total amount of unamortized capitalized costs
to the value of future net revenues, based on current prices and costs.
Capitalized costs of proved oil and gas properties, after considering
estimated dismantlement, restoration and abandonment costs, net of estimated
salvage values, are depreciated and
23
<PAGE>
depleted on a property-by-property basis by the unit-of-production method using
proved developed reserves. The costs of unproved oil and gas properties are
generally aggregated and amortized over a period that is based on the average
holding period for such properties and the Company's experience of successful
drilling. Properties related to gathering and pipeline systems and equipment
are depreciated using the straight-line method based on estimated useful lives
ranging from 10 to 25 years. Certain other assets are also depreciated on a
straight-line basis.
Future estimated plug and abandonment cost is accrued and amortized over the
productive life of the oil and gas properties. The accrued liability for plug
and abandonment cost is included in accumulated depreciation, depletion and
amortization.
Upon the sale or retirement of a property, the cost and related accumulated
depreciation, depletion, and amortization are removed from the consolidated
financial statements, and the resultant gain or loss, if any, is recognized.
Revenue Recognition and Gas Imbalances
The Company applies the sales method of accounting for natural gas revenue.
Under this method, revenues are recognized based on the actual volume of natural
gas sold to purchasers. Natural gas production operations may include joint
owners who take more or less than the production volumes entitled to them on
certain properties. Volumetric production is monitored to minimize these
natural gas imbalances. A natural gas imbalance liability is recorded in other
liabilities in the consolidated balance sheet if the Company's excess takes of
natural gas exceed its estimated remaining recoverable reserves for such
properties.
Income Taxes
The Company follows the asset and liability method in accounting for income
taxes. Under this method, deferred tax assets and liabilities are recorded for
the estimated future tax consequences attributable to the differences between
the financial carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using
the tax rate in effect for the year in which those temporary differences are
expected to turn around. The effect of a change in tax rates on deferred tax
assets and liabilities is recognized in the year of the enacted rate change.
Natural Gas Measurement
The Company records estimated amounts for natural gas revenues and natural gas
purchase costs based on volumetric calculations under its natural gas sales and
purchase contracts. Variances or
24
<PAGE>
imbalances resulting from such calculations are inherent in natural gas sales,
production, operation, measurement, and administration. Management does not
believe that differences between actual and estimated natural gas revenues or
purchase costs attributable to the unresolved variances or imbalances are
material.
Accounts Payable
This account includes credit balances to the extent that checks issued have
not been presented to the Company's bank for payment. These credit balances
included in accounts payable were approximately $6.9 million and $6.1 million at
December 31, 1994 and 1993, respectively.
Earnings Per Common Share
Earnings per common share is computed by dividing net income, as adjusted for
dividends on preferred stock, by the weighted average number of shares of common
stock ("Common Stock") outstanding during the respective periods. The dilutive
effect of stock options on earnings per common share is insignificant for all
periods and is not included in the computation of earnings per common share.
Both the $3.125 cumulative convertible and 6% convertible redeemable preferred
stock ("preferred stock"), issued May 1993 and May 1994, respectively, had an
antidilutive effect on earnings per common share. The preferred stock was
determined not to be a common stock equivalent at the time of issuance.
Risk Management Activities
From time to time, the Company enters into certain commodity derivative
contracts as a hedging strategy to manage commodity price risk associated with
its inventories, production or other contractual commitments. The natural gas
price swap is the type of derivative instrument utilized by the Company. A
natural gas price swap is an agreement between two parties to exchange periodic
payments, usually on a monthly basis. One party pays a fixed price while the
other party typically pays a variable price. Notional quantities of natural gas
are used in each agreement, as the agreements do not involve the physical
exchange or delivery of natural gas. Gains or losses on these hedging
activities are recognized over the period that the inventory, production or
other underlying commitment is hedged. Unrealized gains or losses associated
with any natural gas price swap contracts not considered to be a hedge are
recognized currently. The Company did not have any non-hedge natural gas price
swap contracts in 1994.
The Company has also entered into certain interest rate swap
25
<PAGE>
agreements matched to its 12-year 10.18% senior notes. Similar in concept to a
natural gas price swap, an interest rate swap is an agreement to exchange
periodic payments between two parties. One party's payment is based on a fixed
interest rate times a notional principal balance. The other party applies the
same notional principal balance times a variable interest rate. The net
difference that is paid or received by the Company is charged or credited to
interest expense over the term of the agreements.
Cash Equivalents
The Company considers all highly liquid short-term investments with original
maturities of three months or less to be cash equivalents.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
<TABLE>
<CAPTION>
December 31,
----------------------
1994 1993
---------- ----------
(in thousands)
<S> <C> <C>
Unproved Oil and Gas Properties.. $ 20,847 $ 12,277
Proved Oil and Gas Properties.... 796,390 533,110
Gathering and Pipeline Systems... 146,131 134,262
Land, Building and Improvements.. 5,533 7,376
Other............................ 13,875 11,554
--------- ---------
982,776 698,579
Accumulated Depreciation,
Depletion and Amortization...... (347,842) (298,309)
--------- ---------
$ 634,934 $ 400,270
========= =========
</TABLE>
At December 31, 1994, the Company's total future plug and abandonment cost
was estimated to be $24.4 million, of which $14.4 million and $14.3 million at
December 31, 1994 and 1993, respectively, were accrued as a component of
depreciation, depletion and amortization.
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
<TABLE>
<CAPTION>
December 31,
--------------------
1994 1993
--------- ---------
(in thousands)
<S> <C> <C>
Accounts Receivable
Trade Accounts.............................. $36,246 $32,527
Income Taxes................................ -- 1,660
Other Accounts.............................. 3,245 1,753
------- -------
39,491 35,940
Allowance for Doubtful Accounts.............. (1,325) (644)
------- -------
$38,166 $35,296
======= =======
</TABLE>
26
<PAGE>
<TABLE>
<S> <C> <C>
Accounts Payable
Trade Accounts.............................. $10,818 $ 8,727
Natural Gas Purchases....................... 7,938 4,301
Royalty and Other Owners.................... 12,691 5,445
Capital Costs............................... 4,097 5,721
Dividends Payable........................... 1,404 506
Taxes Other Than Income..................... 690 820
Other Accounts.............................. 2,352 1,018
------- -------
$39,990 $26,538
======= =======
Accrued Liabilities
Employee Benefits........................... $ 3,182 $ 3,702
Taxes Other Than Income..................... 7,886 3,437
Interest Payable............................ 1,742 1,092
Other Accrued............................... 940 1,992
------- -------
$13,750 $10,223
======= =======
Other Liabilities
Postretirement Benefits Other Than Pension.. $ 898 $ 1,764
Accrued Pension Cost........................ 2,299 1,964
Taxes Other Than Income..................... 1,593 2,176
Other....................................... 570 579
------- -------
$ 5,360 $ 6,483
======= =======
</TABLE>
4. INVENTORIES
Inventories are comprised of the following:
<TABLE>
<CAPTION>
December 31,
-------------------
1994 1993
-------- --------
(in thousands)
<S> <C> <C>
Natural Gas in Storage....................... $ 5,777 $ 4,722
Tubular Goods and Well Equipment............. 2,120 1,712
Exchange Balances............................ 487 (741)
------- -------
$ 8,384 $ 5,693
======= =======
</TABLE>
5. DEBT AND CREDIT AGREEMENTS
Short-Term Debt
The Company has a $5.0 million unsecured short-term line of credit with a bank
which it uses as part of its cash management program. The interest rate on the
line of credit is at the bank's prime rate. At December 31, 1994 and 1993, the
debt outstanding was zero and $0.5 million, respectively.
Senior Notes
In May 1990, the Company issued an aggregate principal amount of $80 million
of its 12-year 10.18% senior notes (the "Senior Notes") to a group of nine
institutional investors in a private placement offering. The Senior Notes
require five equal annual principal payments beginning in 1998. The Company may
prepay all or any portion of the indebtedness on any date with a prepayment
27
<PAGE>
premium. The Company's effective interest rates for the Senior Notes in the two
years ended December 31, 1994 and 1993 were 10.65% and 9.99%, respectively, due
to the impact of the interest rate swap instruments obtained in 1993 (see
"Interest Rate Swap Agreements" in Note 15. Financial Instruments). The Senior
Notes contain restrictions on the merger of the Company or any subsidiary with a
third party other than under certain limited conditions, as well as various
other restrictive covenants customarily found in such debt instruments,
including a restriction on the payment of dividends or the repurchase of equity
securities. Such covenants about dividends and equity securities are less
restrictive than the covenants contained in the Credit Facility referred to
below.
Revolving Credit Agreement
In January 1990, the Company entered into an $85 million Revolving Credit
Agreement (the "Credit Facility") with a bank (later expanded to six banks). In
1994, the Company amended certain terms of its Credit Facility to increase the
aggregate commitment amount to $300 million. The available credit line is
subject to adjustment from time-to-time on the basis of the projected present
value (as determined by a petroleum engineer's report incorporating certain
assumptions provided by the lender) of estimated future net cash flows from
certain proved oil and gas reserves and other assets of the Company. If
supported by such an adjustment, the borrowing capacity may be increased up to
$300 million. At present the Company's available credit line is $260 million.
Interest rates are principally based on a reference rate of either the rate for
certificates of deposit ("CD rate") or LIBOR, plus a margin, or the prime rate.
The margin above the reference rate is presently equal to 3/4 of 1% for the
LIBOR based rate, or 7/8 of 1% for the CD based rate. The Credit Facility
provides for a commitment fee on the unused available balance at an annual rate
of 3/8 of 1% and a commitment fee on the unavailable balance of the credit line
at an annual rate of 1/4 of 1%. The Company's effective interest rates for the
Credit Facility in the three years ended December 31, 1994, 1993 and 1992 were
5.7%, 4.6% and 6.3%, respectively. Although the revolving term of the Credit
Facility expires in June 1995, it may be extended with the banks' approval. If
such term is not extended, the indebtedness outstanding will be payable in 24
quarterly installments. Interest rates and commitment fees are subject to
increase if the indebtedness is greater than 80% of the Company's debt limit of
$340 million, as noted below. The Credit Facility contains various restrictive
covenants customarily found in such facilities, including restrictions (i)
prohibiting the merger of the Company or any subsidiary with a third party other
than under certain limited conditions, (ii) prohibiting the sale of all or
substantially all of the Company's or any subsidiary's assets to a third party,
and (iii) restricting certain payments associated with repurchasing equity
28
<PAGE>
securities of the Company or declaring dividends ("Restricted Payments", as
defined in the Credit Facility), if immediately prior to or after giving effect
to such payments, the aggregate of such Restricted Payments exceeds 15% of cash
flows available for debt service, as defined in the Credit Facility, or an event
of default has occurred under the Credit Facility. In addition, the Credit
Facility prohibits the Company and its subsidiaries from incurring recourse
indebtedness (determined on a consolidated basis) in excess of the debt limit
(presently $340 million) subject to certain adjustments, including sales or
acquisitions of oil and gas properties and other changes in projected cash flows
available for debt service.
6. MAJOR CUSTOMER
The Company had sales to no customer which exceeded 10 percent of the
Company's revenues in the years ended December 31, 1994, 1993 and 1992.
7. POSTEMPLOYMENT BENEFITS
Prior to 1993, postemployment benefit expenses were recognized on a pay-as-
you-go basis. In 1993, the Company adopted SFAS 112, "Employers' Accounting for
Postemployment Benefits". There was no cumulative effect attributable to the
change in accounting for postemployment benefits. Postemployment benefit
expense was $0.4 million and $0.6 million for the years ended December 31, 1994
and 1993, respectively.
8. EMPLOYEE BENEFIT PLANS
Pension Plan
The Company has a non-contributory, defined benefit pension plan covering all
full-time employees. The benefits for this plan are based primarily on years of
service and pay near retirement. Plan assets consist principally of fixed
income investments and equity securities. The Company funds the plan in
accordance with the Employee Retirement Income Security Act of 1974 and Internal
Revenue Code limitations.
The Company has a non-qualified equalization plan to ensure payments to
certain executive officers of amounts to which they are already entitled under
the provisions of the pension plan, but which are subject to limitations imposed
by federal tax laws. This plan is unfunded.
29
<PAGE>
Net periodic pension cost of the Company for the years ended December 31,
1994, 1993 and 1992 are comprised of the following:
<TABLE>
<CAPTION>
1994 1993 1992
------- ------ ------
(in thousands)
<S> <C> <C> <C>
Qualified:
Current Year Service Cost............... $ 901 $ 816 $ 787
Interest Accrued on Pension Obligation.. 652 578 542
Actual Return on Plan Assets............ (428) (366) (342)
Net Amortization........................ 102 118 124
Other, Net.............................. -- -- (183)(1)
------ ------ -----
Net Periodic Pension Cost............... $1,227 $1,146 $ 928
====== ====== =====
Non-Qualified:
Current Year Service Cost............... $ 134 $ 84 $ 49
Interest Accrued on Pension Obligation.. 32 5 13
Net Amortization........................ 49 33 20
Other, Net.............................. -- -- 268(2)
------ ------ -----
Net Periodic Pension Cost............... $ 215 $ 122 $ 350
====== ====== =====
</TABLE>
---------------
(1) In accordance with SFAS 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Plans and for Termination Benefits," the
Company recorded a $183 thousand net curtailment gain in the qualified plan
for 1992 as result of the cost reduction program which reduced the
Company's work force by 12%.
(2) Reflects the impact of a special early retirement election by an executive
officer. Based on SFAS 88, the Company recorded a charge to earnings of
approximately $370 thousand for a special termination benefit and
recognized a $102 thousand net settlement gain. The termination and
retirement liabilities were settled by a lump sum payment to the retiring
executive.
The following table sets forth the funded status of the Company's pension
plans at December 31, 1994 and 1993, respectively:
30
<PAGE>
<TABLE>
<CAPTION>
1994 1993
------------------------- --------------------------
Qualified Non-Qualified Qualified Non-Qualified
--------- ------------- --------- -------------
(in thousands)
<S> <C> <C> <C> <C>
Actuarial Present Value of:
Vested Benefit Obligation............. $ 3,680 $ 68 $ 3,481 $ --
Accumulated Benefit Obligation........ 4,258 182 4,090 126
Projected Benefit Obligation.......... $ 8,395 $ 385 $ 8,737 $ 421
Plan Assets at Fair Value............. 4,861 -- 4,243 --
------- ----- ------- -----
Projected Benefit Obligation in
Excess of Plan Assets................ 3,534 385 4,494 421
Unrecognized Net Gain (Loss).......... 972 70 (121) (137)
Unrecognized Prior Service Cost....... (1,316) (537) (1,418) (581)
------- ----- ------- -----
Accrued (Prepaid) Pension Cost........ $ 3,190 $ (82) $ 2,955 $(297)
======= ===== ======= =====
</TABLE>
Assumptions used to determine benefit obligations and pension
costs are as follows:
<TABLE>
<CAPTION>
1994 1993 1992
------- ------ -------
<S> <C> <C> <C>
Discount Rate....................... 8.50% 7.50% 8.75%(1)
Rate of Increase in Compensation
Levels............................. 5.50% 5.50% 6.00%
Long-Term Rate of Return on Plan
Assets............................. 9.00% 9.00% 9.00%
</TABLE>
-----------
(1) Represents the discount rate used to compute pension costs. An 8.25%
discount rate was used to determine the benefit obligations.
Savings Investment Plan
The Company has a Savings Investment Plan (the "SIP") which is a defined
contribution plan. The Company matches a portion of employees' contributions.
Participation in the SIP is voluntary and all regular employees of the Company
are eligible to participate. The Company charged to expense plan contributions
of $0.9 million, $0.7 million and $0.7 million in 1994, 1993, and 1992,
respectively. Effective February 1, 1994, the Company's common stock was added
as an investment option within the SIP. At December 31, 1994, approximately 16
thousand shares of Common Stock were issued and outstanding through the SIP.
Postretirement Benefits Other Than Pensions
In addition to providing pension benefits, the Company provides certain health
care and life insurance benefits ("postretirement benefits") for retired
employees, including their spouses, eligible dependents and surviving spouses
("retirees"). Substantially all employees become eligible for these benefits if
they meet certain age and service requirements at retirement. The Company was
providing postretirement benefits to 234 retirees and 250 retirees at the end of
1994 and 1993, respectively.
31
<PAGE>
The Company adopted SFAS 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions", in 1992 and elected to amortize the accumulated
postretirement benefit obligation at January 1, 1992 (the "Transition
Obligation") over 20 years.
The amortization benefit of the unrecognized Transition Obligation in 1994 and
1993, presented in the table below, is due to a cost-cutting amendment to the
postretirement medical benefits in 1993. The amendment prospectively reduced
the unrecognized Transition Obligation by $9.8 million and is amortized over a
5.75 year period beginning in 1993.
Postretirement benefit costs recognized in the years ended December 31, 1994,
1993 and 1992 are comprised of the following:
<TABLE>
<CAPTION>
1994 1993 1992
------- ------ ------
(in thousands)
<S> <C> <C> <C>
Service Cost of Benefits Earned During the Year.. $ 152 $ 210 $ 558
Interest Cost on the Accumulated Postretirement
Benefit Obligation.............................. 470 667 1,367
Amortization Benefit of the Unrecognized Gain.... (207) -- --
Amortization Cost (Benefit) of the Unrecognized
Transition Obligation........................... (859) (858) 846
----- ----- ------
Total Postretirement Benefit Cost (Benefit)...... $(444) $ 19 $2,771
===== ===== ======
</TABLE>
The health care cost trend rate used to measure the expected cost in 1995
for medical benefits to retirees over age 65 was 8.5%, graded down to a trend
rate of 0% in 2001. The health care cost trend rate used to measure the
expected cost in 1995 for retirees under age 65 was 10.0%, graded down to a
trend rate of 0% in 2001. Provisions of the plan should prevent further
increases in employer cost after 2001.
The weighted average discount rate used in determining the actuarial present
value of the benefit obligation at December 31, 1994 and 1993 was 8.5% and 7.5%,
respectively.
A one-percentage-point increase in health care cost trend rates for future
periods would increase the accumulated net postretirement benefit obligation by
approximately $143 thousand and, accordingly, the total postretirement benefit
cost recognized in 1994 would have also increased by approximately $15 thousand.
32
<PAGE>
The funded status of the Company's postretirement benefit obligation at
December 31, 1994 and 1993 is comprised of the following:
<TABLE>
<CAPTION>
1994 1993
-------- --------
(in thousands)
<S> <C> <C>
Plan Assets at Fair Value................................ $ -- $ --
Accumulated Postretirement Benefits Other Than Pensions
Retirees................................................ 4,007 5,023
Active Participants..................................... 1,503 1,474
------- -------
5,510 6,497
Unrecognized Cumulative Net Gain......................... 3,735 2,755
Unrecognized Transition Obligation....................... (7,990) (7,131)
------- -------
Accrued Postretirement Benefit Liability................ $ 1,255 $ 2,121
======= =======
</TABLE>
9. INCOME TAXES
Income tax expense (benefit) is summarized as follows:
<TABLE>
<CAPTION>
December 31,
---------------------------
1994 1993 1992
------- ------ ------
(in thousands)
<S> <C> <C> <C>
Current:
Federal................................................... $ -- $ (796) $ 7,145(2)
State..................................................... 153 (103) 198
------- ------ -------
Total.................................................... 153 (899) 7,343
------- ------ -------
Deferred:
Federal................................................... (1,987) 4,909(1) (6,440)(2)
State..................................................... 1,191 2,149 5,096
------- ------ -------
Total.................................................... (796) 7,058 (1,344)
------- ------ -------
Total Income Tax Expense (Benefit)....................... $ (643) $6,159 $ 5,999
======= ====== =======
</TABLE>
--------------
(1) Deferred tax liability was reduced by a $0.8 million alternative minimum
tax adjustment in 1993.
(2) Alternative minimum tax expense for 1992 of $4.2 million, less a 1991
accrual adjustment of $0.3 million, was offset against the existing deferred tax
liability.
33
<PAGE>
Total income taxes were different than the amounts computed by applying the
statutory federal income tax rate as follows:
<TABLE>
<CAPTION>
December 31,
---------------------------
1994 1993 1992
------- -------- --------
(in thousands)
<S> <C> <C> <C>
Statutory Federal Income Tax Rate............ 35% 35% 34%
Computed "Expected" Federal Income Tax....... $(574) $3,388 $2,797
State Income Tax, Net of Federal Income Tax.. 873 1,330 3,494
Tax Settlement, Net.......................... -- -- 444
Other, Net................................... (942) 1,441 (736)
----- ------ ------
Total Income Tax Expense (Benefit)........... $(643) $6,159 $5,999
===== ====== ======
</TABLE>
Income taxes for the year ended December 31, 1993 were increased by $2.3
million due to a change in the federal income tax rate.
Effective June 30, 1992, the Company took a charge against income of $2.7
million, or 13 cents per share, to reflect the settlement of the previously
disclosed tax dispute with Cabot concerning Cabot's demand for federal and state
taxes for the years ended September 30, 1990 and 1989. In conjunction with the
settlement, Cabot also assumed the responsibility for most potential audit
adjustments of federal and consolidated state tax returns filed for all periods
the Company was consolidated into Cabot's tax returns.
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax liabilities and deferred tax assets as of December
31, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
1994 1993
--------- -------
(in thousands)
<S> <C> <C>
Deferred Tax Liabilities:
Property, Plant and Equipment.................... $138,287 $89,871
-------- -------
Deferred Tax Assets:
Alternative Minimum Tax Credit Carryforwards..... 5,108 3,912
Net Operating Loss Carryforwards................. 11,748 3,809
Deferred Compensation / Retirement Related
Items Accrued for Financial Reporting Purposes.. 3,624 3,452
-------- -------
Net Deferred Tax Assets........................... 20,480 11,173
-------- -------
Net Deferred Tax Liabilities...................... $117,807 $78,698
======== =======
</TABLE>
Deferred tax liabilities includes a $40.2 million increase attributable to the
WERCO acquisition in May, 1994 (see Note 13. WERCO Acquisition). At December
31, 1994, the Company has a net operating loss carryforward for regular income
tax reporting purposes of $33.4 million which will begin expiring in 2006. In
addition, the Company has an alternative minimum tax credit carryforward of $5.1
million which does not expire and is
34
<PAGE>
available to offset regular income taxes in future years to the extent that
regular income taxes exceed the alternative minimum tax in any such year.
10. COMMITMENTS AND CONTINGENCIES
Lease Commitments
The Company leases certain transportation vehicles, warehouse facilities,
office space and machinery and equipment under cancelable and non-cancelable
leases, most of which expire within five years and may be renewed by the
Company. Rent expense under such arrangements totalled $5.5 million, $5.0
million and $5.1 million for the years ended December 31, 1994, 1993 and 1992,
respectively. Future minimum rental commitments under non-cancelable leases in
effect at December 31, 1994 are as follows:
<TABLE>
<CAPTION>
(in thousands)
<S> <C>
1995........ $ 3,904
1996........ 3,132
1997........ 2,738
1998........ 2,051
1999........ 1,520
Thereafter.. 2,604
-------
$15,949
=======
</TABLE>
Minimum rental commitments are not reduced by minimum sublease rental income
of $2.4 million due in the future under non-cancelable subleases.
Contingencies
The Company is a defendant in various lawsuits and is involved in other gas
contract issues. In the opinion of the Company, final judgements or
settlements, if any, which may be awarded in connection with any one or more of
these suits and claims could be significant to the results of operations of any
period but would not have a material adverse effect on the Company's financial
position.
Effective December 1, 1994, the Company reached a settlement with John Hancock
Mutual Life Insurance Company ("John Hancock") that resolved a 1992 claim
asserted by John Hancock. The settlement provides for the exchange between John
Hancock and the Company of interests in certain proved oil and gas properties.
The Company transferred to John Hancock partial working interest in certain
wells located in West Virginia in exchange for partial working interest in
certain wells located in Pennsylvania and New York. The Company continues to
operate all of these properties. As an exchange of interests in oil and gas
properties, the
35
<PAGE>
Company's net book basis in the property interests transferred to John Hancock
became the basis for the property interests received from John Hancock.
Accordingly, no gain or loss was recognized in the property exchange.
In February 1993, Barby Energy Corporation and certain other parties filed
suit in Beaver County, Oklahoma against the Company to determine the rights and
interests of the parties in and to the oil, gas and other minerals underlying a
tract of land in Beaver County, Oklahoma, to quiet title to said mineral estate,
and for an accounting and payment of production proceeds attributable to said
mineral estate. Specifically at issue is whether there was continuous
production from an oil and gas well located on the property since July 5, 1965.
Plaintiffs claim there was a cessation of production, and therefore, all right,
title and interest to such property reverted to them and that they are entitled
to all revenues from such production since the date cessation of production
occurred. The Company believes that it holds a valid oil and gas lease covering
the interest claimed by the plaintiffs. The trial commenced on February 6, 1995
and, pursuant to an order entered on February 13, 1995, the judge denied and
overruled all of the plaintiffs' claims. The judge's decision may be appealed
by the plaintiffs. Although no assurances can be given, the Company believes
that the ultimate outcome of this litigation will not have a material adverse
effect on the Company's financial position.
11. CASH FLOW INFORMATION
Cash paid for interest and income taxes is as follows:
<TABLE>
<CAPTION>
At December 31,
----------------------------------
1994 1993 1992
------- -------- ---------
(in thousands)
<S> <C> <C> <C>
Interest...... $16,002 $10,536 $ 9,668
Income Taxes.. $ 210 $ 1,282 $10,010
</TABLE>
At December 31, 1994 and 1993, the majority of cash and cash equivalents is
concentrated in one financial institution. Additionally, the Company has
accounts receivable that are subject to credit risk.
12. CAPITAL STOCK
Incentive Plans
On May 20, 1994, the 1994 Long-Term Incentive Plan and the 1994 Non-Employee
Director Stock Option Plan were approved by the shareholders. The Company has
two other stock option plans - the Incentive Stock Option Plan, adopted in 1989,
and the 1990 Non-Employee Director Stock Option Plan. Under these four plans
(the
36
<PAGE>
"Incentive Plans"), incentive and non-statutory stock options, stock
appreciation rights ("SARs") and stock awards may be granted to key employees
and officers of the Company, and non-statutory stock options may be granted to
non-employee directors of the Company. A maximum of 2,660,000 shares of Common
Stock, par value $0.10 per share, are subject to issuance under the Incentive
Plans. All stock options have a maximum term of five or ten years from the date
of grant and vest over time. The options are issued at market value on the date
of grant. The minimum exercise period for stock options is six months from the
date of grant. Under the 1994 Long-Term Incentive and Non-Employee Director
Stock Option Plans, no stock options or stock awards were granted in 1994. No
SARs have been granted under the Incentive Plans. Information regarding the
Company's Incentive Plans is summarized below:
<TABLE>
<CAPTION>
At December 31,
--------------------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Shares Under Option at Beginning of Period.. 684,525 639,200 439,750
Granted..................................... 301,900 197,300 302,700
Exercised................................... 12,050 126,835 --
Surrendered or Expired...................... 20,600 25,140 103,250(1)
-------- -------- --------
Shares Under Option at End of Period........ 953,775 684,525 639,200
======== ======== ========
Option Price Range per
Share at End of Period.................... $ 13.25- $ 13.25- $ 13.25-
$ 26.00 $ 26.00 $ 17.19
Options Exercisable at End of Period........ 447,907 236,120 316,340
</TABLE>
--------------
(1) Options surrendered of 100 thousand were replaced with the granting of 100
thousand SARs (not issued under the Incentive Plans) with a base price of
$16.125. On April 1, 1993, such SARs were exercised in full.
Dividend Restrictions
The determination of the amount of future cash dividends, if any, to be
declared and paid on the Common Stock will be subject to the discretion of the
Board of Directors of the Company and will depend upon, among other things, the
Company's financial condition, funds from operations, the level of its capital
and exploration expenditures, and its future business prospects. The Company's
credit agreements restrict certain payments ("Restricted Payments," as defined
in the credit agreements) associated with (i) purchasing, redeeming, retiring or
otherwise acquiring any capital stock of the Company or any option, warrant or
other right to acquire such capital stock or (ii) declaring any dividend, if
immediately prior to or after giving effect to such payments, the aggregate of
such Restricted Payments exceeds 15% of cash flows available for debt service,
as defined in the Credit Facility, or an event of default has occurred under the
37
<PAGE>
credit agreements. Furthermore, the Credit Facility specifies a minimum cash
flow to debt service coverage ratio. As of December 31, 1994, such restrictions
had no adverse impact on the Company's ability to pay regular dividends.
Purchase Rights
On January 21, 1991, the Board of Directors adopted the Preferred Stock
Purchase Rights Plan and declared a dividend distribution of one right for each
outstanding share of Common Stock. Each right becomes exercisable, at a price
of $55, when any person or group has acquired, obtained the right to acquire or
made a tender or exchange offer for beneficial ownership of 15 percent or more
of the Company's outstanding Common Stock, except pursuant to a tender or
exchange offer for all outstanding shares of Common Stock deemed to be fair and
in the best interests of the Company and its stockholders by a majority of the
independent Continuing Directors (as defined in the plan). Each right entitles
the holder, other than the acquiring person or group, to purchase one one-
hundredth of a share of Series A Junior Participating Preferred Stock ("Junior
Preferred Stock"), or to receive, after certain triggering events, Common Stock
or other property having a market value of twice the exercise price of each
right. After the rights become exercisable, if the Company is acquired in a
merger or other business combination in which it is not the survivor or 50
percent or more of the Company's assets or earning power are sold or
transferred, each right entitles the holder to purchase common stock of the
acquiring company with a market value equal to twice the exercise price of each
right. At December 31, 1994, there were no shares of Junior Preferred Stock
issued.
The rights, which expire on January 21, 2001, and the exercise price are
subject to adjustment and may be redeemed by the Company for $0.01 per right at
any time before they become exercisable. Under certain circumstances, the
Continuing Directors may opt to exchange one share of Common Stock for each
exercisable right.
Preferred Stock
At December 31, 1994 and 1993, 692,439 shares of the Company's $3.125
cumulative convertible preferred stock ("$3.125 preferred stock") were issued
and outstanding. Each share has a stated value of $50 and is convertible any
time by the holder into Common Stock at a conversion price of $21 per share,
subject to adjustment. The $3.125 preferred stock is redeemable by the Company
for a stated redemption price per share, starting at $55 per share in 1994 and
declining to $50 per share in 2003, plus accrued dividends. Prior to May 31,
1997, the Company's option to redeem the $3.125 preferred stock is subject to a
provision that the Common Stock closing price must equal at least 130% of
38
<PAGE>
the conversion price for 20 of 30 consecutive trade days. The Company also has
the option to convert the $3.125 preferred stock to Common Stock at the
conversion price provided the Company has the right to redeem the $3.125
preferred stock, as described above, and the closing price of the Common Stock
is at least equal to the conversion price for 20 consecutive trading days.
On May 2, 1994, the Company issued 1,134,000 shares of 6% convertible
redeemable preferred stock ("6% preferred stock") in connection with the WERCO
acquisition (See Note 13. WERCO Acquisition). Each share has 1.7 voting rights,
a stated value of $50 and is convertible at any time by the holder into Common
Stock at a conversion price of $28.75 per share, subject to adjustment. On or
after the fourth anniversary of the date of issuance, the 6% preferred stock is
redeemable, in whole or in part, at the Company's option price of $50 per share.
Before the fifth anniversary date, the Company may opt to redeem the 6%
preferred stock in shares of Common Stock, using the market price on the date
redeemed, plus a cash payment for the accrued dividends due on the shares
redeemed. After the fifth anniversary date, the $50 per share redemption price
is payable in cash, plus a cash payment for accrued dividends due on the shares
redeemed.
13. WERCO ACQUISITION
The Company completed the merger between a Company subsidiary and Washington
Energy Resources Company ("WERCO"), a wholly-owned subsidiary of Washington
Energy Company. The Company acquired the stock of WERCO in a tax-free exchange.
Total capitalized costs related to the acquisition were $216.2 million,
comprised of cash and stock consideration of $176.0 million (subject to certain
post-closing adjustments in 1995) and a $40.2 million non-cash component
relating to the deferred income taxes attributable to the difference between the
tax and book bases of the acquired properties, as required by SFAS 109,
"Accounting for Income Taxes". The acquisition, effective May 2, 1994, was
recorded using the purchase method. Excluded from the transaction were certain
firm transportation, storage and other contractual arrangements of WERCO's
marketing affiliate which were retained by Washington Energy Company.
The Company issued 2,133,000 shares of Common Stock and 1,134,000 shares of 6%
convertible redeemable preferred stock ($50 per share stated value) to
Washington Energy Company in exchange for the capital stock of WERCO. The 6%
preferred stock is convertible into 1,972,174 shares of Common Stock at $28.75
per share. In addition, the Company advanced cash to repay WERCO's intercompany
indebtedness. The intercompany debt of WERCO was $63.7 million, as adjusted.
The oil and gas properties, located in the Green River Basin
39
<PAGE>
of Wyoming and in the Gulf Coast, had an estimated 191 Bcfe of proved reserves
at the acquisition date, of which 82% was natural gas. Average net daily
production from such properties in 1994 was approximately 51.1 Mmcfe. The
properties include 483 wells (134 net).
The following represents the pro forma results of operations as if the WERCO
acquisition had occurred at the beginning of 1993:
<TABLE>
<CAPTION>
1994 1993
------- --------
(in thousands except per share amounts)
<S> <C> <C>
Total Revenue......................... $259,068 $221,717
Net Loss Applicable to Common Shares.. $ (7,291) $ (1,191)
Loss per Common Share................. $ (0.32) $ (0.05)
</TABLE>
The results of operations presented above do not purport to be indicative of
the results of future operations, nor the results of historical operations had
the acquisition occurred as of the assumed dates.
14. SUBSEQUENT EVENT (UNAUDITED)
On January 26, 1995, the management announced a plan to be implemented in
the first quarter of 1995 through which the Company expects to:
i) Maximize the Company's discretionary cash flows by reducing its capital
spending to concentrate on the highest potential return opportunities,
selling selective non-core properties, and applying excess cash to debt
reduction;
ii) Consolidate the Company's management in the Rocky Mountain, Anadarko and
onshore Gulf Coast areas into a single Western Region; and,
iii) Reduce the number of Company employees by approximately 15%.
These steps will result in a one-time charge to earnings of approximately
$3.5 million, or $0.15 per share, in the first quarter of 1995. The expected
reduction in recurring expenses is approximately $3 million in 1995 and $4
million a year thereafter.
15. FINANCIAL INSTRUMENTS
The following disclosures on the estimated fair value of financial
instruments are presented in accordance with SFAS 107, "Disclosures about Fair
Value of Financial Instruments". Fair
40
<PAGE>
value, as defined in SFAS 107, is the amount at which the instrument could be
exchanged currently between willing parties. The Company uses available
marketing data and valuation methodologies to estimate fair value of debt.
<TABLE>
<CAPTION>
December 31, 1994 December 31, 1993
---------------------- --------------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
--------- ----------- -------- -----------
(in thousands)
<S> <C> <C> <C> <C>
Debt
Senior Notes............................ $ 80,000 $ 84,700 $ 80,000 $ 95,000
Credit Facility......................... 188,000 188,000 89,000 89,000
Short-Term Line and Other Note Payable.. 363 386 530 530
-------- -------- -------- --------
$268,363 $273,086 $169,530 $184,530
======== ======== ======== ========
Other Financial Instruments
Interest Rate Swaps..................... $ -- $ (5,296) $ -- $ (184)
Gas Price Swaps......................... -- (1,010) -- 45
</TABLE>
Long-Term Debt
The fair value of long-term debt is the estimated cost to acquire the debt,
including a premium or discount for the differential between the issue rate and
the year-end market rate. The fair value of the Senior Notes is based upon
interest rates available to the Company. The Credit Facility and the short-term
line approximate fair value because these instruments bear interest at rates
based on current market rates.
Interest Rate Swap Agreements
In November 1993, the Company executed reverse interest rate swap agreements
with four banks that effectively converted the Company's $80 million fixed rate
notes into variable rate notes. Under the swap agreements, the Company pays a
variable rate of interest that is based on the six-month LIBOR. The banks pay
the Company fixed rates of interest that average 5.00%. The four agreements
have notional principal of $20 million each with terms of two, three, four and
five years. The fair value is determined by obtaining termination values from
third parties (see Note 1. "Risk Management Activities").
In January 1995, the Company entered into four additional swap agreements
which effectively fixed interest payments on the original interest rate swaps
until May 1997. As a result, the Company will record a charge to interest
expense of approximately $4.4 million over the period of the additional swaps.
For the two original interest rate swap agreements with terms ending on November
1997 and 1998, respectively, the Company is exposed to interest rate risk for
the periods extending beyond May 1997.
41
<PAGE>
Gas Price Swaps
The Company has entered into several price swap agreements with seven
counterparties. In a majority of the natural gas price swap agreements, the
Company receives a fixed price ("fixed price swap contracts") for a notional
quantity of natural gas in exchange for its paying a variable price based on a
market based index, such as the NYMEX gas futures. The fixed price swap
contracts are used to hedge price risk associated with the Company's production.
During 1994, the fixed prices received on closed contracts ranged from $1.58 to
$3.19 per Mmbtu on total notional quantities of 14,931,000 Mmbtu. One fixed
price swap contract was open at December 31, 1994 with a fixed price of $2.08
per Mmbtu, a contract period extending to March 1995 and open notional
quantities totalling 400,000 Mmbtu. In the other natural gas price swap
contracts, in which the Company receives the variable price and pays a fixed
price ("variable price swap contracts"), the fixed prices paid on closed
contracts in 1994 ranged from $1.87 to $2.41 on total notional quantities of
4,089,000 Mmbtu. The Company uses the variable price swap contract to hedge the
price risk associated with its purchased gas. One variable price swap contract
was open at December 31, 1994 with a fixed price of $1.60, a contract period
extending to December 1995, open notional quantities totalling 5,475,000 Mmbtu
and a margin call requirement for obligations over $2 million. This variable
price swap contract partially hedges the price of third-party purchased gas used
to supply a long-term, fixed price contract. The estimated fair value of price
swaps presented above are for hedged transactions in which gains or losses are
recognized in results of operations over the periods that production or
purchased gas is hedged (see Note 1. "Risk Management Activities").
The Company is exposed to market risk on these open contracts to the extent
of changes in market prices for natural gas. However, the market risk exposure
on these hedged contracts is offset by the gain or loss recognized upon the
ultimate sale of the natural gas that is hedged.
Credit Risk
Although notional contract amounts are used to express the volume of gas
price and interest rate swap agreements, the amounts potentially subject to
credit risk, in the event of non-performance by third parties, are substantially
smaller. The Company does not anticipate any material impact to its financial
results due to non-performance by the third parties.
42
<PAGE>
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
OIL AND GAS RESERVES
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates may occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil and
condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered through
wells and equipment in place and under operating methods being utilized at the
time the estimates were made.
Estimates of proved and proved developed reserves at December 31, 1994, 1993
and 1992 were based on studies performed by the Company's petroleum engineering
staff. The estimates prepared by the Company's engineering staff were reviewed
by Miller and Lents, Ltd., who indicated in their recent letter dated February
10, 1995 that, based on their investigation and subject to the limitations
described in such letter, it was their judgement that the results of those
estimates and projections for 1994 were reasonable in the aggregate.
No major discovery or other favorable or adverse event subsequent to December
31, 1994 is believed to have caused a material change in the estimates of proved
or proved developed reserves as of that date.
43
<PAGE>
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (CONTINUED)
The following table sets forth the Company's net proved reserves, including
changes therein, and proved developed reserves for the periods indicated, as
estimated by the Company's engineering staff. All reserves are located in the
United States (more than 99%) or Canada.
<TABLE>
<CAPTION>
Natural Gas
---------------------------------
December 31,
---------------------------------
1994 1993 1992
---------- -------- -----------
(millions of cubic feet)
<S> <C> <C> <C>
PROVED RESERVES
Beginning of Year............................ 808,280 724,666 716,450
Revisions of Prior Estimates................. (24,627) (18,270) (8,947)
Extensions, Discoveries and Other Additions.. 64,829 58,265 56,875
Production................................... (58,319) (46,050) (45,466)
Purchases of Reserves in Place............... 168,957 93,131 5,771
Sales of Reserves in Place................... (6,037) (3,462) (17)
------- ------- -------
End of Year.................................. 953,083 808,280 724,666
======= ======= =======
PROVED DEVELOPED RESERVES..................... 805,913 669,672 583,673
======= ======= =======
</TABLE>
<TABLE>
<CAPTION>
Liquids
------------------------------
December 31,
--------------------------------
1994 1993 1992
--------- -------- ---------
(thousands of barrels)
<S> <C> <C> <C>
PROVED RESERVES
Beginning of Year............................ 2,826 1,799 1,213
Revisions of Prior Estimates (98) (355) 235
Extensions, Discoveries and Other Additions.. 181 437 511
Production................................... (824) (345) (162)
Purchases of Reserves in Place............... 5,992 1,331 3
Sales of Reserves in Place................... (41) (41) (1)
------- ------- -------
End of Year.................................. 8,036 2,826 1,799
======= ======= =======
PROVED DEVELOPED RESERVES..................... 7,704 2,346 1,510
======= ======= =======
</TABLE>
44
<PAGE>
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (CONTINUED)
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table sets forth the aggregate amount of capitalized costs
relating to natural gas and crude oil producing activities and the aggregate
amount of related accumulated depreciation, depletion and amortization.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
1994 1993 1992
---------- -------- --------
(in thousands)
<S> <C> <C> <C>
Aggregate Capitalized Costs Relating
to Oil and Gas Producing Activities.. $980,676 $696,520 $587,213
======== ======== ========
Aggregate Accumulated Depreciation,
Depletion and Amortization........... $346,080 $296,764 $281,280
======== ======== ========
</TABLE>
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities and Finding and Development Costs of Proved Reserves
Costs incurred in property acquisition, exploration and development activities
were as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------
1994 1993 1992
---------- -------- --------
(in thousands)
<S> <C> <C> <C>
Property Acquisition Costs--Proved........................ $184,835 $ 82,364 $ 1,586
Property Acquisition Costs--Unproved...................... 4,685 3,893 1,891
Exploration and Extension Well Costs...................... 9,402 7,487 6,703
Development Costs......................................... 46,463 34,183 19,443
-------- -------- -------
Total costs............................................. $245,385 $127,927 $29,623
======== ======== =======
(A) Proved Reserves of Additions, includes Drilling
of Acquired Proved Undeveloped Locations in Connection
with the Emax Acquisition and Revisions (in Natural
Gas Equivalents), Mmcfe (1).......................... 56,900 45,700 52,400
-------- -------- -------
(B) Proved Reserves of (A) Above, Plus Purchases of
Reserves in Place, Mmcfe (1).......................... 245,600 141,600 58,200
-------- -------- -------
Calculated Finding and Development
Cost of Proved Reserves, (A) Above, $/Mcfe (1).......... $ 0.97 $ 0.92 $ 0.47
-------- -------- -------
Calculated Finding and Development
Cost of Proved Reserves, (B) Above, $/Mcfe (1).......... $ 0.98 $ 0.88 $ 0.45
-------- -------- -------
------------------
</TABLE>
(1) The Company has included the reserve additions and related costs
associated with the development drilling of proved undeveloped locations in 1994
and 1993 acquired in connection with the Emax acquisition. In addition,
exploration expenses that are administrative in nature are excluded from the
finding and development cost calculation.
45
<PAGE>
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (CONTINUED)
Historical Results of Operations from Oil and Gas Producing Activities
The results of operations for the Company's oil and gas producing activities
were as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------
1994 1993 1992
------- -------- -------
(in thousands)
<S> <C> <C> <C>
Operating Revenues.......................... $126,307 $105,247 $96,726
Costs and Expenses
Production................................ 39,114 31,065 26,425
Other Operating........................... 16,787 17,476 18,081
Exploration............................... 8,014 6,943 6,227
Depreciation, Depletion and Amortization.. 48,075 31,648 28,622
-------- -------- -------
Total Cost and Expenses................. 111,990 87,132 79,355
-------- -------- -------
Income Before Income Taxes.................. 14,317 18,115 17,371
Provision for Income Taxes.................. 5,011 6,340 5,906
-------- -------- -------
Results of Operations....................... $ 9,306 $ 11,775 $11,465
======== ======== =======
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
The following information has been developed utilizing procedures prescribed
by SFAS 69 and based on natural gas and crude oil reserve and production volumes
estimated by the Company's engineering staff. It may be useful for certain
comparison purposes, but should not be solely relied upon in evaluating the
Company or its performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted Future Net
Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account
in reviewing the following information: (i) future costs and selling prices
will probably differ from those required to be used in these calculations; (ii)
due to future market conditions and governmental regulations, actual rates of
production achieved in future years may vary significantly from the rate of
production assumed in the calculations; (iii) selection of a 10% discount rate
is arbitrary and may not be reasonable as a measure of the relative risk
inherent in realizing future net oil and gas revenues; and (iv) future net
revenues may be subject to different rates of income taxation.
46
<PAGE>
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (CONTINUED)
Under the Standardized Measure, future cash inflows were estimated by applying
year-end oil and gas prices adjusted for fixed and determinable escalations, to
the estimated future production of year-end proved reserves. The average prices
related to proved reserves at December 31, 1994, 1993 and 1992 were for oil
($/Bbl) $17.06, $16.20 and $19.90, respectively, and for natural gas ($/Mcf)
$1.88, $2.40 and $2.42, respectively. Future cash inflows were reduced by
estimated future development and production costs based on year-end costs in
order to arrive at net cash flow before tax. Future income tax expense has been
computed by applying year-end statutory tax rates to future pretax net cash
flows, reduced by the tax basis of the properties involved. Use of a 10%
discount rate is required by SFAS 69.
Management does not rely solely upon the following information in
making investment and operating decisions. Such decisions are based upon a wide
range of factors, including estimates of probable as well as proved reserves,
and varying price and cost assumptions considered more representative of a range
of possible economic conditions that may be anticipated.
47
<PAGE>
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (CONTINUED)
Standardized Measure is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------
1994 1993 1992
------- -------- -------
(in thousands)
<S> <C> <C> <C>
Future Cash Inflows........................ $2,219,559 $2,190,400 $1,998,543
Future Production and Development Costs.... (723,767) (670,390) (593,094)
---------- ---------- ----------
Future Net Cash Flows Before Income Taxes.. 1,495,792 1,520,010 1,405,449
10% Annual Discount for Estimated Timing
of Cash Flows............................ (880,130) (878,912) (825,564)
---------- ---------- ----------
Standardized Measure of Discounted Future
Net Cash Flows Before Income Taxes....... 615,662 641,098 579,885
Future Income Tax Expenses, Net of 10%
Annual Discount (1)...................... (125,167) (173,198) (175,308)
---------- ---------- ----------
Standardized Measure of Discounted Future
Net Cash Flows........................... $ 490,495 $ 467,900 $ 404,577
========== ========== ==========
</TABLE>
--------------
(1) Future income taxes before discount were $433,212, $480,817 and $456,000
for the years ended December 31, 1994, 1993 and 1992, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
1994 1993 1992
-------- -------- --------
(in thousands)
<S> <C> <C> <C>
Beginning of Year $ 467,900 $404,577 $362,361
Discoveries and Extensions, Net of
Related Future Costs...................... 24,188 48,183 47,177
Net Changes in Prices and Production Costs.. (133,750) (53,822) 32,671
Accretion of Discount....................... 64,110 57,989 51,907
Revisions of Previous Quantity Estimates,
Timing and Other.......................... (32,654) (33,731) (21,526)
Development Costs Incurred.................. 16,631 18,617 15,593
Sales and Transfers, Net of
Production Costs.......................... (87,193) (74,182) (70,301)
Net Purchases of Reserves in Place.......... 123,232 98,159 5,295
Net Change in Income Taxes.................. 48,031 2,110 (18,600)
--------- -------- --------
End of Year................................. $ 490,495 $467,900 $404,577
========= ======== ========
</TABLE>
48
<PAGE>
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
Net Acreage by Area of Operation
<TABLE>
<CAPTION>
December 31, 1994
-----------------------------------
Developed Undeveloped Total
---------- ----------- ---------
<S> <C> <C> <C>
Appalachian Region 758,238 383,692 1,141,930
Western Region 241,708 220,403 462,111
999,946 604,095 1,604,041
</TABLE>
Productive Well Summary
The following table reflects the Company's ownership at December 31, 1994
in gas and oil wells in the Appalachian Region (consisting of various fields
located in West Virginia, Pennsylvania, New York, Ohio, Virginia and Kentucky)
and in the Western Region (consisting of various fields located in the Mid-
Continent, including Louisiana, Oklahoma, Texas, Kansas, North Dakota and
Wyoming, and in Canada).
<TABLE>
<CAPTION>
Natural Gas Oil Total
--------------- ------------ --------------
Gross Net Gross Net Gross Net
------- ------ ------ ----- ------ ------
<S> <C> <C> <C> <C> <C> <C>
Appalachian Region 4,108 3,764.6 17 14.6 4,125 3,779.2
Western Region 1,119 545.0 631 189.4 1,750 734.4
5,227 4,309.6 648 204.0 5,875 4,513.6
</TABLE>
"Productive" wells are producing wells and wells capable of production.
Price Range of Common Stock and Dividends
The Common Stock is listed and principally traded on the NYSE. The following
table sets forth for the periods indicated the high and low sales prices per
share of the Common Stock, as reported in the consolidated transaction reporting
system, and the cash dividends paid per share of the Common Stock:
<TABLE>
<CAPTION>
Cash
High Low Dividends
------- ------- -----------
<S> <C> <C> <C>
1994
First Quarter $23.50 $19.13 $0.04
Second Quarter 23.25 18.75 0.04
Third Quarter 22.25 18.38 0.04
Fourth Quarter 19.88 13.38 0.04
1993
First Quarter $24.13 $15.50 $0.04
Second Quarter 25.88 21.50 0.04
Third Quarter 27.00 20.13 0.04
Fourth Quarter 26.25 17.63 0.04
</TABLE>
49
<PAGE>
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED) - (CONTINUED)
As of January 31, 1995, there were 1,386 registered holders of the Common
Stock. Shareholders include individuals, brokers, nominees, custodians, trustees
and institutions such as banks, insurance companies and pension funds. Many of
these hold large blocks of stock on behalf of other individuals or firms.
Quarterly Financial Information (Unaudited)
<TABLE>
<CAPTION>
First Second Third Fourth Total
------ --------- -------- --------- -------
(In Thousands Except Per Share Amounts)
<S> <C> <C> <C> <C> <C>
1994
Total Revenues $65,840 $56,453 $55,758 $59,016 $237,067
Operating Income 11,580 1,513 (423) 2,343 15,013
Net Income (Loss) 4,682 (2,480) (4,441) (3,205) (5,444)
Earnings (Loss) Per Share $ 0.23 $ (0.11) $ (0.20) $ (0.14) $ (0.25)
1993
Total Revenues $43,475 $38,379 $33,483 $48,958 $164,295
Operating Income 8,290 3,823 2,212 5,682 20,007
Net Income (Loss) 3,895 566 (3,570)(1) 1,197 2,088
Earnings (Loss) Per Share $ 0.19 $ 0.03 $ (0.17)(1) $ 0.06 $ 0.10
</TABLE>
--------------
(1) Includes a $2.3 million charge, or 11 cents a share, due to a federal
income tax rate increase.
50
<PAGE>
Exhibit 21.1
SUBSIDIARIES OF CABOT OIL & GAS CORPORATION
Big Sandy Gas Company
Cabot Oil & Gas Marketing Corporation
Cabot Oil & Gas Production Corporation
Cabot Oil & Gas Trading Corporation
Cabot Oil & Gas U.K. Limited
Cabot Oil & Gas Western Corporation
Cabot Petroleum North Sea, Ltd.
Cranberry Pipeline Corporation
Franklin Brine Treatment Corporation
Industrial Gas Corporation
<PAGE>
Exhibit 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements
of Cabot Oil & Gas Corporation on Form S-8 filed on June 23, 1991, October 29,
1993 and on May 20, 1994 of our report dated March 3,1995, on our audits of the
consolidated financial statements of Cabot Oil & Gas Corporation as of December
31, 1994 and 1993, and for each of the three years in the period ended December
31, 1994, which report is incorporated by reference in this Annual Report on
Form 10-K.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 24, 1995
<PAGE>
EXHIBIT 23.2
MILLER AND LENTS, LTD
OIL AND GAS CONSULTANTS
TWENTY-SEVENTH FLOOR
1100 LOUISIANA
HOUSTON, TEXAS 77002-5216
TELEPHONE 713 651-9455
TELEFAX 713 654-9914
March 14, 1995
Cabot Oil & Gas Corporation
15375 Memorial Drive
Houston, Texas 77079
Re: Securities and Exchange Commission
Form 10-K of Cabot Oil & Gas Corporation
Gentleman:
The firm of Miller & Lents, Ltd. consents to the use of its name and to the
use of its report dated February 10, 1995 regarding the Cabot Oil & Gas
Corporation Proved Reserves and Future Net Revenues as of January 1, 1995, which
report is to be included by reference in Form 10-K to be filed by Cabot Oil &
Gas Corporation with the Securities and Exchange Commission.
Miller & Lents, Ltd. has no interests in Cabot Oil & Gas Corporation, or in
any of its affiliated companies or subsidiaries and is not to receive any such
interest as payment for such report and has no director, officer or employee
employed or otherwise connected with Cabot Oil & Gas Corporation. We are not
employed by Cabot Oil & Gas Corporation on a contingent basis.
Very truly yours,
MILLER & LENTS, LTD.
By /s/ James A. Cole
--------------------------
Vice President
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 3,773
<SECURITIES> 0
<RECEIVABLES> 39,491
<ALLOWANCES> (1,325)
<INVENTORY> 8,384
<CURRENT-ASSETS> 52,019
<PP&E> 982,776
<DEPRECIATION> (347,842)
<TOTAL-ASSETS> 688,352
<CURRENT-LIABILITIES> 53,740
<BONDS> 268,363
<COMMON> 152,607
0
91,322
<OTHER-SE> (847)
<TOTAL-LIABILITY-AND-EQUITY> 688,352
<SALES> 232,668
<TOTAL-REVENUES> 237,067
<CGS> 222,133
<TOTAL-COSTS> 222,133
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 16,651
<INCOME-PRETAX> (1,638)
<INCOME-TAX> (643)
<INCOME-CONTINUING> (5,444)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (5,444)
<EPS-PRIMARY> (0.25)
<EPS-DILUTED> 0
</TABLE>
<PAGE>
Exhibit 99
[LETTERHEAD OF MILLER AND LENTS, LTD. APPEARS HERE]
February 10, 1995
Cabot Oil & Gas Corporation
15375 Memorial Drive
Houston, Texas 77079
Re: Review of Proved Reserves
And Future Net Revenues
As of January 1, 1995
Gentlemen:
At your request, we reviewed the estimates of Proved Reserves of oil and
gas and the Future Net Revenues associated with these reserves that Cabot Oil &
Gas Corporation, hereinafter Cabot, attributes to its net interests in oil and
gas properties as of January 1, 1995. Cabot's estimates, shown below, are in
accordance with the definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a).
<TABLE>
<CAPTION>
Proved Reserves
-------------------------------------
Developed Undeveloped Total
----------- ----------- ----------
<S> <C> <C> <C>
Net Oil, MBbls. 7,703.7 332.5 8,036.2
Net Gas, MMcf 805,913.2 147,170.0 953,083.2
Future Net Revenues
Undiscounted, M$ 1,335,945.0 159,847.0 1,495,792.0
Discounted at 10 Percent, M$ 580,224.2 35,437.6 615,661.8
</TABLE>
<PAGE>
MILLER AND LENTS, LTD.
Cabot Oil & Gas Corporation February 10, 1995
Page 2
Based on our investigations and subject to the limitations described
hereinafter, it is our judgment that (1) Cabot has an effective system for
gathering data and documenting information required to estimate its Proved
Reserves and to project its Future Net Revenues, (2) in making its estimates and
projections, Cabot used appropriate engineering, geologic, and evaluation
principles and techniques that are in accordance with practices generally
accepted in the petroleum industry, and (3) the results of those estimates and
projections are, in the aggregate, reasonable.
All of the reserves discussed herein are located within the continental
United States. Gas volumes were estimated at the appropriate pressure base and
temperature base that are established for each well or field by the applicable
sales contract or regulatory body. Total gas reserves were obtained by summing
the reserves for all the individual properties and are therefore stated herein
at a mixed pressure base.
Cabot represents that the future net revenues reported herein were computed
based on prices being received for oil and gas as of Cabot's fiscal year end,
December 31, 1994, and are in accordance with Securities and Exchange Commission
guidelines. The Present Value of Future Net Revenues was computed by discounting
the Future Net Revenues at ten percent per annum. Estimates of Future Net
Revenues and the Present Value of Future Net Revenues are not intended and
should not be interpreted to represent fair market values for the estimated
reserves.
In conducting our investigations, we reviewed the pertinent available
engineering, geological and accounting information for each well or designated
property to satisfy ourselves that Cabot's estimates of reserves and future
production forecasts and economic projections are, in the aggregate, reasonable.
We independently selected a sampling of properties in each region and reviewed
the direct operating expenses and product prices used in the economic
projections.
In its estimates of Proved Reserves and Future Net Revenues associated with
its Proved Reserves, Cabot has considered that a portion of its facilities
associated with the movement of its gas in the Appalachian Region to its markets
are unusual in that the construction and operation of these facilities are
highly dependent on its producing operations. Cabot has deemed the portion of
the cost of these facilities associated with its revenue interest gas are costs
that are attributable to its oil and gas producing activities, and accordingly,
has included these costs in its computation of the Future Net Revenues
associated with its Proved Reserves.
Reserve estimates were based on decline curve extrapolations, material
balance calculations, volumetric calculations, analogies, or combinations of
these methods for each well, reservoir, or field. Reserve estimates from
volumetric calculations and from analogies are often
<PAGE>
MILLER AND LENTS, LTD.
Cabot Oil & Gas Corporation February 10, 1995
Page 3
less certain than reserve estimates based on well performance obtained over a
period during which a substantial portion of the reserves were produced.
In making its projections, Cabot estimated yearly well abandonment costs
except where salvage values were assumed to offset these expenses. Costs for
possible future environmental claims were not included. Cabot's estimates
include no adjustments for production prepayments, exchange agreements, gas
balancing, or similar arrangements. We were provided with no information
concerning these conditions and we have made no investigations of these matters
as such was beyond the scope of this investigation.
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on accepted
standards of professional investigation but are subject to those generally
recognized uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies and market
conditions different from those employed in this study may cause the total
quantity of oil or gas to be recovered, actual production rates, prices
received, or operating and capital costs to vary from those presented in this
report.
In conducting these evaluations, we relied upon production histories,
accounting and cost data, and other financial, operating, engineering, and
geological data supplied by Cabot. To a lesser extent, non-proprietary data
existing in the files of Miller and Lents, Ltd., and data obtained from
commercial services were used. We also relied, without independent verification,
upon Cabot's representation of its ownership interests, the current prices, and
the transportation fees applicable to each property.
Miller and Lents, Ltd. is an independent oil and gas consulting firm. None
of the principals of this firm have any financial interests in Cabot or any of
its affiliated companies. Our fee is not contingent upon the results of our work
or report, and we have not performed other services for Cabot that would affect
our objectivity.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ JAMES A. COLE
______________________
James A. Cole
Vice President
WC/cw
